Distributed remote logging

ABSTRACT

Methods, systems, and apparatuses for remote well operation control. Methods include conducting, with a plurality of remote well operation control hosts operating on corresponding remote well logging data acquisition management systems, a well operation using a well operation system at a well, wherein the well operation system includes a carrier having disposed thereon at least one logging instrument. Methods may include establishing a first operational control relationship between the carrier and a first of the plurality of remote well operation control hosts sufficient for the first remote well operation control host to control the carrier; and establishing a second operational control relationship between a selected one of the at least one logging instrument and a second remote well operation control host different than the first, the operational control relationship sufficient for the second remote well operation control host to control the at least one logging instrument and receive logging data.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. application Ser. No.15/600,035 filed May 19, 2017, the entire disclosure of which isincorporated herein by reference in its entirety.

FIELD OF THE DISCLOSURE

This disclosure generally relates to borehole tools, and in particularto methods and apparatuses for conducting well logging.

BACKGROUND OF THE DISCLOSURE

Drilling wells for various purposes is well-known. Such wells may bedrilled for geothermal purposes, to produce hydrocarbons (e.g., oil andgas), to produce water, and so on. Well depth may range from a fewthousand feet to 25,000 feet or more.

In conventional oil well logging, during well drilling and/or after awell has been drilled, instruments may be conveyed into the borehole andused to determine one or more parameters of interest related to theformation. A rigid or non-rigid conveyance device is often used toconvey the instruments, often as part of a tool or a set of tools, andthe conveyance device may also provide communication channels forsending information up to the surface.

During or after drilling, these instruments in the wellbore are used tocarry out any number of subterranean investigations of the earthformation or of infrastructure associated with the wellbore. Severalinstruments may be housed in a single tool, multiple tools may beconnected on a single conveyance device, or both. Thus, the tools mayinclude variety of sensors and/or electronics for formation evaluation,monitoring and controlling the instruments, monitoring and controllingthe conveyance device, and so on. Aspects of control of theseinstruments to conduct investigations are carried out by electronicsdownhole and by control equipment and/or personnel at the well surface,which may be connected by a local area network (‘LAN’). Optionally,remotely located control equipment and/or personnel may send commands tologging instruments, e.g., over a wide-area network (‘WAN’).

A LAN is a computer network that spans a relatively small area. ManyLANs are confined to a single building or group of buildings, or asingle well site. However, one LAN can be connected to other LANs overany distance (e.g., via telephone lines, fiber networks, radio waves,etc.). A wide-area network (‘WAN’) is a system of LANs connected in thisway. The Internet is an example of a WAN.

SUMMARY OF THE DISCLOSURE

In aspects, the present disclosure is related to methods, systems, andapparatuses for conducting remote well operations, and more particularlyto remote well operation control. Methods include conducting, with aplurality of remote well operation control hosts operating oncorresponding remote well logging data acquisition management systems, awell operation using a well operation system at a well, wherein the welloperation system includes a carrier having disposed thereon at least onelogging instrument. Methods may include establishing a first operationalcontrol relationship between the carrier and a first of the plurality ofremote well operation control hosts sufficient for the first remote welloperation control host to control the carrier responsive to at least onewell-logging command from the first remote well operation control host;and establishing a second operational control relationship between aselected one of the at least one logging instrument and a second remotewell operation control host of the plurality different than the first,the operational control relationship sufficient for the second remotewell operation control host to control the at least one logginginstrument responsive to at least one well-logging command from thesecond remote well operation control host and receive logging data.

Methods may include operating the carrier responsive to at least onewell-logging command received from the first remote well operationcontrol host of the plurality; and operating the logging instrumentresponsive to at least one well-logging command received from the secondremote well operation control host of the plurality. Methods mayinclude, over at least one interval of time, identically processing thelogging data at the local well operation control host in parallel withprocessing the logging data at the second remote well operation controlhost, substantially simultaneously.

Methods may include, during a logging operation, using a Wide AreaNetwork (WAN) to transmit substantially all substantially maximumresolution raw well logging data generated by the selected one of the atleast one logging instrument from the well to at least one of theplurality of remote well operation control hosts; and using the loggingdata to control the well operation with at least one second command insubstantially real-time from the at least one of the plurality of remotewell operation control hosts responsive to the logging data received.Methods may include operating a second logging instrument responsive toat least one well-logging command from the second remote well operationcontrol host, and/or operating a second logging instrument on thecarrier responsive to at least one well-logging command from a thirdremote well operation control host of the plurality different than thefirst and second. The carrier may be at least one of i) a drill string;ii) a wireline; and iii) a downhole tool.

The well operation may comprise at least one of: i) geosteering; ii)drilling at least one borehole in a formation; iii) performingmeasurements on a formation; iv) estimating parameters of a formation;v) installing equipment in a borehole; vi) evaluating a formation; vii)optimizing present or future development in a formation or in a similarformation; viii) optimizing present or future exploration in a formationor in a similar formation; ix) producing one or more hydrocarbons from aformation; x) performing maritime logging operations of a seabed.

Methods may include conducting, with the plurality of remote welloperation control hosts operating on the corresponding remote welllogging data acquisition management systems, a second well operationusing a second well operation system at a second well remote from thefirst well, wherein the second well operation system includes a secondconveyance device having disposed thereon a third logging instrument anda fourth logging instrument.

Methods may include establishing a third operational controlrelationship between the third logging instrument and a first of theplurality of remote well operation control hosts sufficient for thefirst remote well operation control host to control the third logginginstrument responsive to at least one well-logging command from thefirst remote well operation control host; establishing a fourthoperational control relationship between a fourth logging instrument andthe second remote well operation control host, the operational controlrelationship sufficient for the second remote well operation controlhost to control the fourth logging instrument responsive to at least onewell-logging command from the second remote well operation control host.

Methods may include enabling i) operation of the carrier by the firstremote well operation control host, ii) operation of the selected one ofthe at least one logging instrument by the second remote well operationcontrol host, iii) operation of the third logging instrument by thefirst remote well operation control host, and iv) operation of thefourth logging instrument by the second remote well operation controlhost by: using a master remote well operation control host, of theplurality of remote well operation control hosts, on a correspondingremote well logging data acquisition management system to establish thethird operational control relationship and the fourth operationalcontrol relationship.

Methods may include enabling operation of the carrier by the firstremote well operation control host and operation of the selected one ofthe at least one logging instrument by the second remote well operationcontrol host by using a master remote well operation control host, ofthe plurality of remote well operation control hosts, on a correspondingremote well logging data acquisition management system to distributecontrol capabilities by establishing the first operational controlrelationship and the second operational control relationship.

Methods may include establishing the first operational controlrelationship and the second operational control relationship independence upon a role associated with at least one of: i) the firstremote well operation control host, and ii) the second remote welloperation control host.

Methods may include conducting, with a plurality of remote welloperation control hosts operating on corresponding remote well loggingdata acquisition management systems, a well operation using a welloperation system at a well, wherein the well operation system includes acarrier having disposed thereon a plurality of logging instruments.Methods may include establishing a first operational controlrelationship between a first logging instrument of the plurality oflogging instruments and a first of the plurality of remote welloperation control hosts, the operational control relationship sufficientfor the first remote well operation control host to control the firstlogging instrument responsive to at least one well-logging command fromthe first remote well operation control host; establishing a secondoperational control relationship between a second of the plurality oflogging instruments and a second remote well operation control host ofthe plurality different than the first, the operational controlrelationship sufficient for the second remote well operation controlhost to control the second logging instrument responsive to at least onewell-logging command from the second remote well operation control host.

General method embodiments may include methods, systems, and apparatusesfor conducting well operations. Methods embodiments may includeallocating control of an operational resource located at a well, thecontrol of the resource sufficient for conducting at least a portion ofthe well operations. This may be carried out by maintaining a databaseassociating a plurality of remote well operational control hosts withcorresponding roles, wherein at least some roles of the correspondingroles are associated with privileges to corresponding operationalresources; and allocating control of an operational resource to a firstremote well operational control host of the plurality in dependence uponthe role associated with the remote well operational control host. Thismay be carried out by referencing those privileges associated with therole. The database may be remote from the local well operation controlhost, and the method may include retrieving to the local well operationcontrol host the role associated with the remote well operationalcontrol host of the plurality.

Methods may include determining an operational state of the resource.Allocating control of the operational resource to the remote welloperational control host may include allocating control of theoperational resource to the remote well operational control host independence upon the role associated with the remote well operationalcontrol host and the operational state of the resource. Methods mayinclude determining an operational state of the well; allocating controlof the operational resource to the remote well operational control hostmay comprise allocating control of the operational resource to theremote well operational control host in dependence upon the roleassociated with the remote well operational control host and theoperational state of the well.

Methods may include allocating control of the operational resource to alocal well operation control host while in a default operational state.The allocating may be an initial allocation of the role. The allocatingmay be a role modification. The role modification may includeidentifying the first remote well operational control host as beingassociated with the role modification; and associating the first remotewell operational control host with the role. A role modification mayinclude identifying a second remote well operational control host asbeing associated with the role modification; and associating the secondremote well operational control host with the role. The rolemodification may include modifying at least a pre-existing roleassociated with the first remote well operational control host to therole; and modifying at least the role, associated with a second remotewell operational control host, to another role. Methods may includetriggering the role modification in response to detecting a role shiftevent.

Roles may be associated with constraints and/or a credentials profile. Aremote well operational control host may have credentials associatedwith it. Identifying a remote well operational control host forassociation with privileges may include selecting the remote welloperational control host in dependence upon the comparison. It mayinclude selecting the remote well operational control host in dependenceupon the comparison and at least one selection rule.

In aspects, the present disclosure is related to methods, systems, andapparatuses for remote well logging. Methods include conducting, with aplurality of remote well operation control hosts operating oncorresponding remote well logging data acquisition management systems, awell logging operation using a well logging system at a logging site,wherein the well logging system includes a conveyance device havingdisposed thereon a first logging instrument and a second logginginstrument; operating the first logging instrument responsive to atleast one well-logging command from a first remote well operationcontrol host of the plurality; and operating the second logginginstrument responsive to at least one well-logging command from a secondremote well operation control host of the plurality different than thefirst.

The conveyance device, or carrier, may include at least one of i) adrill string; and ii) a wireline. Where the carrier comprises a drillstring, the logging tool may include a bottom hole assembly (BHA).Methods may include performing drilling operations by rotating a drillbit disposed at a distal end of the drill string and taking well loggingmeasurements to generate raw well logging data during drillingoperations.

Methods may include acquiring raw well logging data from the firstlogging instrument and the second logging instrument by a local welloperation control host on a corresponding well logging data acquisitionmanagement system at the logging site; mirroring the acquired raw welllogging data to at least one of the plurality of remote well operationcontrol hosts; and issuing a further command from at least one of theplurality of remote well operation control hosts responsive to theacquired raw well logging data.

Methods may include identically processing the logging data at the localwell operation control host in parallel with processing the logging dataat the plurality of remote well operation control hosts. Methods mayinclude, during a logging operation, using a Wide Area Network (WAN) totransmit substantially all raw well logging data generated by the firstlogging instrument and the second logging instrument from the loggingsite to at least one of the plurality of remote well operation controlhosts; and using the logging data to control the logging operation withat least one second command in substantially real-time from the at leastone of the plurality of remote well operation control hosts responsiveto the logging data received.

Methods may include determining a value for at least one data transfercharacteristic (e.g. average throughput, downtime, or failure in a givenperiod) of the WAN with respect to the at least one of the plurality ofremote well operation control hosts; making a comparison of the valuefor the at least one data transfer characteristic with at least oneoperational sufficiency profile, the at least one operationalsufficiency profile representative of data transfer characteristicvalues indicating data transfer sufficient for control of the loggingoperation in substantially real-time; and implementing a contingentoperational mode in dependence upon the comparison. The implementedcontingent operational mode may be selected from a plurality ofavailable contingent operational modes in dependence upon an order ofpriority of at least one of: i) logging data from the first logginginstrument; ii) logging data from the second logging instrument. Theimplemented contingent operational mode may be selected from a pluralityof available contingent operational modes in dependence upon an order ofpriority of operations between a first logging operation associated withthe first logging instrument and second logging operation associatedwith the first logging instrument.

Methods may include synchronizing the plurality of remote well operationcontrol hosts with the local well operation control host. The welloperation control host may be remote from the logging site. Methods mayinclude conveying the conveyance device to intersect a volume ofinterest relating to the first logging instrument via tool commands froma first of the plurality of remote well operation control hosts; andassigning control of the conveyance device, upon the device intersectingthe volume of interest, from the first of the plurality of remote welloperation control hosts to a second of the plurality of remote welloperation control hosts.

Methods may include, during a logging operation, using a Wide AreaNetwork (WAN) to transmit a virtual presence feed associated with alogging site supervisor from the logging site to at least one of thecorresponding remote well logging data acquisition management systems;and using the virtual presence feed to construct a representation of avirtual presence perspective of the position of the logging sitesupervisor at the logging site, and presenting the representation to aremote well operating engineer at the at least one of the correspondingremote well logging data acquisition management systems. The virtualpresence feed may include information representing video, audio,location data (e.g., GPS data), and so on. Methods may include, duringthe logging operation, using a Wide Area Network (WAN) to transmit audioinstruction data and auxiliary data from the at least one of thecorresponding remote well logging data acquisition management systems tothe logging site; rendering the audio instruction data as audioinstructions via a personal communication system of the logging sitesupervisor; and rendering the auxiliary data on a graphic interface ofthe personal communication system of the logging site supervisor.

The well logging operation may include at least one of: i) geosteering;ii) drilling at least one borehole in a formation; iii) performingmeasurements on a formation; iv) estimating parameters of a formation;v) installing equipment in a borehole; vi) evaluating a formation; vii)optimizing present or future development in a formation or in a similarformation; viii) optimizing present or future exploration in a formationor in a similar formation; ix) producing one or more hydrocarbons from aformation; x) performing maritime logging operations of a seabed.

Methods may include conducting, with the plurality of remote welloperation control hosts operating on the corresponding remote welllogging data acquisition management systems, a second well loggingoperation using a second well logging system at a second logging siteremote from the first logging site, wherein the second well loggingsystem includes a second conveyance device having disposed thereon athird logging instrument and a fourth logging instrument, comprising:operating the third logging instrument responsive to at least onewell-logging command from the first remote well operation control hostof the plurality; and operating the fourth logging instrument responsiveto at least one well-logging command from the second remote welloperation control host. Methods may include comprising enabling i)operation of the first logging instrument by the first remote welloperation control host, ii) operation of the second logging instrumentby the second remote well operation control host, iii) operation of thethird logging instrument by the first remote well operation controlhost, and iv) operation of the fourth logging instrument by the secondremote well operation control host by using a master remote welloperation control host, of the plurality of remote well operationcontrol hosts, on a corresponding remote well logging data acquisitionmanagement system to distribute control capability for a particularinstrument to a particular remote well operation control host.

Methods may include enabling operation of the first logging instrumentby the first remote well operation control host and operation of thesecond logging instrument by the second remote well operation controlhost by using a master remote well operation control host, of theplurality of remote well operation control hosts, on a correspondingremote well logging data acquisition management system to distributecontrol capability for a particular instrument to a particular remotewell operation control host.

Methods may include distributing control capability in dependence uponan operational mode. All the acquired well logging data may pass throughthe corresponding remote well logging data acquisition management systemof the master remote well operation control host. Methods may includecontrolling the conveyance device using at least one well operationcontrol host of the plurality. Methods may include enabling operation ofthe first logging instrument by the first remote well operation controlhost and operation of the second logging instrument by the second remotewell operation control host by using a distributed remote cluster toprovide logging data related to the first logging instrument and thesecond logging instrument to the first remote well operation controlhost and the second remote well operation control host.

Methods as described above implicitly utilize at least one processor.Some embodiments include a non-transitory computer-readable mediumproduct accessible to the processor and having instructions thereonthat, when executed, causes the at least one processor to performmethods described above. Apparatus embodiments may include, in additionto specialized borehole measurement equipment and conveyance apparatus,at least one processor and a computer memory accessible to the at leastone processor comprising a computer-readable medium having instructionsthereon that, when executed, causes the at least one processor toperform methods described above.

Examples of some features of the disclosure may be summarized ratherbroadly herein in order that the detailed description thereof thatfollows may be better understood and in order that the contributionsthey represent to the art may be appreciated.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference shouldbe made to the following detailed description of the embodiments, takenin conjunction with the accompanying drawings, in which like elementshave been given like numerals, wherein:

FIG. 1A is a schematic diagram of an example well logging system inaccordance with embodiments of the present disclosure;

FIG. 1B is a schematic diagram of an example drilling system inaccordance with embodiments of the present disclosure;

FIG. 2 illustrates a system for remote well logging in accordance withembodiments of the present disclosure;

FIG. 3 illustrates a distributed software architecture in accordancewith embodiments of the present disclosure;

FIG. 4 illustrates methods of remote well logging in accordance withembodiments of the present disclosure;

FIGS. 5A-5D illustrate systems for remote well logging in accordancewith embodiments of the present disclosure;

FIG. 6 illustrates another system for remote well logging in accordancewith embodiments of the present disclosure;

FIGS. 7A-7C illustrate a virtual presence system for incorporation insystem embodiments in accordance with the present disclosure;

FIGS. 8A-8C illustrate the use of roles in establishing controlrelationships;

FIGS. 9A & 9B illustrate control relationships between actors andresources;

FIG. 10 shows a flow chart illustrating an example of incorporation ofrole switching into a winch control operational process in accordancewith embodiments of the present disclosure.

DETAILED DESCRIPTION

Aspects of the present disclosure relate to apparatus and methods forwell operation control, including controlling well operations such aswell logging, drilling, productions operations, and so on. Operationsmay include movement and/or activation of tools in the borehole,extension of the borehole, activation and regulation of supportingsystems, installation of infrastructure, or measurement andinterpretation of physical phenomena indicative of parameters ofinterest of the formation, the borehole, infrastructure installed in theformation (e.g., casing), downhole fluids in one of these, orcombinations of the same. Techniques described herein are particularlysuited to cooperative multi-instrument subterranean investigation.Further aspects include improved control systems, techniques, andstructures for subterranean exploration, investigation, monitoring, anddevelopment.

In conventional oil well logging, during well drilling and/or after awell has been drilled, instruments conveyed in the wellbore are used inorder to carry out any number of subterranean investigations of theearth formation, the borehole, fluid in the formation or borehole, or ofinfrastructure associated with the wellbore, all of which may bereferred to as well logging. Aspects of control of these instruments toconduct investigations are carried out by electronics downhole and bycontrol equipment and/or personnel at the well surface.

In the current standard mode of operation in the wireline loggingindustry, all downhole measuring equipment is controlled and sensor datais recorded by local data acquisition systems. The local dataacquisition system may in some cases be controlled by a remote computersystem interface (e.g., using keyboard, mouse, and monitor) over anetwork connection.

Traditionally, of those personnel at the well site, a well operator isthe chief individual responsible for the success of the loggingoperation. Although rewarding, a career as a well operator may be quitedemanding. The well operator (or ‘well operations engineer’) must befamiliar with the functioning of all the instruments conveyed in theborehole, and must understand and communicate job objectives,priorities, and deliverables to other personnel. The well operator mustalso verify functionality of all the instruments and supportinginfrastructure, such as, for example, communications and conveyancedevices. Perhaps most importantly, because many operations requireconveyance of a carrier in the borehole (e.g., a logging run, or trip),the well operator must also be onsite to manage acquisition ofwell-logging data via operations of the instruments in conjunction withthe greater tool system. All logging tools are affected by environmentalconditions. Thus, mitigation of environmental effects with real-timecorrections to instruments, conveyance devices, and infrastructure iscritical to the production of accurate well logging data.

During data acquisition, the well operator leverages his or herexpertise to control the logging instruments downhole in substantiallyreal time. The well operator has a myriad of options available on aminute-by-minute basis to change tool parameters and techniques tooptimize well logging results. Traditionally, well operators at a wellsite have full access to unmitigated (or substantially maximumresolution) raw data communicated uphole from the instruments, althoughconventionally this is not possible for operators using remote control.In operating each instrument, access to substantially all the raw datahas proven critical in optimizing the measurement results from eachinstrument via real-time adjustments to measurement processes. Raw datamay refer to unformatted instrument data representing the instrumentresponse, along with any wrapper necessary for networked or buscommunication, which may or may not be encrypted.

However, as the number and variety of well instruments has proliferatedand the capabilities of (and the logging processes available from) eachinstrument have expanded, demands on operational personnel have exceededthe capabilities of a single well operator, particularly in light ofrequired travel. Typically, a variety of unique instruments are conveyedon the tool string. By unique instruments, it is meant that, withrespect to one another, two or more instruments having mutuallyexclusive measurement subject matter (e.g., acoustic and resistivity andgamma ray measurements) or different tool physics (borehole seismic andacoustic borehole imaging) are mounted on the string. A limited numberof personnel with the right combination of expertise for a particularjob may be required at the same time at wells scattered across theglobe.

Aspects of the present disclosure include methods and systems forconducting distributed remote well operations. Processes employed inperforming well operations may be distributed to a plurality of remotesites, and/or automated to reduce the burden on the well operator at thelocal site. A separate remote subject matter expert may individuallycontrol each particular downhole instrument, tool, or process responsiveto substantially all available logging data. These subject matterexperts are uniquely skilled in operations of the instrument. Each ofthese experts may interact with a different well operation control hostrunning on a separate data acquisition management system at differentlocations, and each system may be tailored to the logging operationsunder its control.

All downhole measuring equipment and sensor data may be controlled andtransmitted by a local data acquisition management system. This localdata acquisition management system may be controlled through a networkby one or more remote data acquisition management systems, each of whichmay include data acquisition control, recording and processingsystem(s). Either the local acquisition system (see 289, FIG. 2) or alocal distribution system (see 803, FIG. 8) may distribute control ofthe instruments, equipment, personnel, and the like, along with accessto data from the local site, by using advanced control architectures asdescribed in greater detail herein below. In particular embodiments,this control and access may be distributed through the granting ofprivileges to and assignment of processes to an actor (e.g., personnel,processing system, or computer process). Distributed control of a wellpresents particular challenges that were previously unrecognized orwhich lacked a solution. Solutions to these challenges are providedherein below.

The raw logging data from the instruments is communicated in full to alocal system (that is, at the well site) for storage and management.Substantially all of the raw logging data is also mirrored to the remotesystem(s) over a network to ensure continuous operation with no dataloss under communication interruptions or equipment malfunctions. Insome implementations, the local system may connect to a remote dataacquisition management system over a network connection, and from thereconnect to multiple remote computer systems, in order to reduce the loadon the network connection between the local and remote systems.

Methods of remote well logging as disclosed herein may includeconducting, with a plurality of remote well operation control hostsoperating on corresponding remote well logging data acquisitionmanagement systems, a well logging operation using a well logging systemat a logging site, wherein the well logging system includes a conveyancedevice having disposed thereon a first logging instrument and a secondlogging instrument; operating the first logging instrument responsive toat least one well-logging command from a first remote well operationcontrol host of the plurality; and operating the second logginginstrument responsive to at least one well-logging command from a secondremote well operation control host of the plurality different than thefirst. The conveyance device may include a tool, tool string, drillstring, or the larger tool delivery system.

Aspects of the present disclosure include systems, devices, products,and methods of well logging using logging instruments in a borehole inan earth formation. Methods may include conveying multiple logginginstruments in the borehole on at least one conveyance device(‘carrier’); taking well logging measurements with the logginginstruments, and estimating a property of a subterranean volume ofinterest.

Aspects of the present disclosure relate to using at least one sensor aspart of one or more downhole well logging instruments to produceinformation responsive to physical phenomena in the earth formation(‘logging information’). The information is indicative of a parameter ofinterest. The term “information” as used herein includes any form ofinformation (analog, digital, EM, printed, etc.), and may include one ormore of: raw data, processed data, and signals. When the information hasa high granularity bearing directly on the instrument sensor response(tool response) to the physical phenomena, it may be referred to as rawlogging data. Logging data is quite voluminous by its nature. Oneprominent characteristic of raw logging data is that it may be subjectto further processing to estimate parameters of interest, and that theparticular algorithms used in this processing is subject to change overtime and in light of the circumstances and operating environment. Thus,to properly conduct well operations remotely, logging data current tothe measurement operation may be a requirement for remote subject matterexperts.

Method embodiments in accordance with the present disclosure may includeestimating a parameter of interest from the information, evaluating theformation using the parameter of interest, and/or performing furtherborehole or formation operations in dependence upon the information, theevaluation, or the parameter. In particular embodiments, a state ofdrilling operations, characteristics of the borehole or formation, ororientation of components of the downhole tool may be estimated usingthe parameter of interest, and then used in performing an operation asdescribed above.

The present disclosure is susceptible to embodiments of different forms.There are shown in the drawings, and herein will be described in detail,specific embodiments of the present disclosure with the understandingthat the present disclosure is to be considered an exemplification ofthe principles of the disclosure, and is not intended to limit thedisclosure to that illustrated and described herein. Indeed, as willbecome apparent, the teachings of the present disclosure can be utilizedfor a variety of well tools and in all phases of well construction andproduction. Accordingly, the embodiments discussed below are merelyillustrative of the applications of the present disclosure.

Referring to FIG. 1A, well logging instruments 10 a, 10 b, and 10 c areshown being lowered into a wellbore 2 penetrating earth formations 13.The instruments 10 a, 10 b, and 10 c may be lowered into the wellbore 2and withdrawn therefrom by a conveyance device comprising tool 10 and anarmored electrical cable 14. The cable 14 and tool 10 may includeembedded conductors for power and/or data for providing signal and/orpower communication between the surface and downhole instruments (e.g.,a seven conductor cable). The cable 14 can be spooled by a winch 7 orsimilar device known in the art. The cable 14 may be electricallyconnected to a data acquisition management system 89 which can include asignal decoding and interpretation unit 16 and a recording unit 12.Signals transmitted by the tool 10 along the cable 14 can be decoded,interpreted, recorded and processed by the respective units in thesystem 89.

In one embodiment, circuitry associated with the tool 10 and instruments14 (described in further detail below with respect to FIG. 2) may beconfigured to take measurements as the tool moves along the longitudinalaxis of the borehole (‘axially’). These instruments 10 a, 10 b, 10 c maygenerate a signal in response to physical phenomena indicative ofproperties of the formation (including, for example, “behind-casingevaluation”), the wellbore, the fluid, and so on (‘parameters ofinterest’).

These parameters of interest may include information relating to ageological parameter, a geophysical parameter, a petrophysicalparameter, and/or a lithological parameter. Thus, the tool 10 mayinclude instruments including sensors for detecting physical phenomenaindicative of parameters of interest such as, for example, formationresistivity, dielectric constant, the presence or absence ofhydrocarbons, acoustic density, bed boundary, formation density, nucleardensity and certain rock characteristics, permeability, capillarypressure, relative permeability, and so on. As one example, thismeasurement information, produced using instrument 10 a, may be used togenerate a resistivity image of the borehole 2 or another electricalparameter of interest of a formation 13, and additional instruments 10 band 10 c may be used to take nuclear and acoustic measurements in theborehole.

For example, the wireline logging tool may be configured to measure oneor more of the following values associated with the formation: (i) aresistivity value, (ii) a density value, (ii) a porosity value, (iii) anatural radiation value, (iv) a borehole image, (v) an acoustic traveltime value, (vi) a nuclear magnetic resonance value, (vii) a pressurevalue, (viii) a well production value, (ix) a residual hydrocarbonsaturation value, and (x) a temperature value, and so on. Thesemeasurements may be substantially continuous, which may be defined asbeing repeated at very small increments of depth and/or azimuth, suchthat the resulting information has sufficient scope and resolution toprovide an image of borehole parameters (e.g., properties of theformation at the borehole).

Systems in accordance with the present disclosure may alternativelyinclude a conventional derrick and a conveyance device, which may berigid or non-rigid, and which may be configured to convey the downholetool 10 in the wellbore. Drilling fluid (‘mud’) may be present in theborehole. The carrier may be a drill string, coiled tubing, a slickline,an e-line, a wireline, etc. Downhole tool 10 may be coupled or combinedwith additional tools. Thus, depending on the configuration, the tool 10may be used during drilling and/or after the wellbore has been formed.While a land system is shown, the teachings of the present disclosuremay also be utilized in offshore or subsea applications. The carrier mayinclude a bottom hole assembly, which may include a drilling motor forrotating a drill bit.

Data acquisition management system 89 receives signals from sensors ofthe instruments and other sensors used in the system 100 and processessuch signals according to programmed instructions provided to the dataacquisition system 89. The data acquisition management system 89 maydisplay desired parameters and other information on a display/monitorthat is utilized by an operator. The data acquisition management system89 may further communicate with a downhole control system at a suitablelocation on downhole tool 10. The data acquisition management system 89may process data relating to the operations and data from instruments 10a, 10 b, 10 c, and may control one or more downhole operations performedby system 100.

Certain embodiments of the present disclosure may be implemented with ahardware environment 21 that includes an information processor 17, aninformation storage medium 13, an input device 11, processor memory 9,and may include peripheral information storage medium 19. The hardwareenvironment may be in the well, at the rig, and/or at a remote location.Moreover, the several components of the hardware environment (ormultiple hardware environments) may be distributed among thoselocations. The input device 11 may be any data reader or user inputdevice, such as data card reader, keyboard, USB port, etc. Theinformation storage medium 13 stores information provided by thedetectors. Information storage medium 13 may include any non-transitorycomputer-readable medium for standard computer information storage, suchas a USB drive, memory stick, hard disk, removable RAM, EPROMs, EAROMs,flash memories and optical disks or other commonly used memory storagesystem known to one of ordinary skill in the art including Internetbased storage. Information storage medium 13 stores a program that whenexecuted causes information processor 17 to execute the disclosedmethod. Information storage medium 13 may also store the formationinformation provided by the user, or the formation information may bestored in a peripheral information storage medium 19, which may be anystandard computer information storage device, such as a USB drive,memory stick, hard disk, removable RAM, or other commonly used memorystorage system known to one of ordinary skill in the art includingInternet based storage. Information processor 17 may be any form ofcomputer or mathematical processing hardware, including Internet basedhardware. When the program is loaded from information storage medium 13into processor memory 9 (e.g. computer RAM), the program, when executed,causes information processor 17 to retrieve detector information fromeither information storage medium 13 or peripheral information storagemedium 19 and process the information to estimate a parameter ofinterest. Information processor 17 may be located on the surface ordownhole.

The term “information” as used herein includes any form of information(analog, digital, EM, printed, etc.). As used herein, a processor is anyinformation processing device that transmits, receives, manipulates,converts, calculates, modulates, transposes, carries, stores, orotherwise utilizes information. In several non-limiting aspects of thedisclosure, an information processing device includes a computer thatexecutes programmed instructions for performing various methods. Theseinstructions may provide for equipment operation, control, datacollection and analysis and other functions in addition to the functionsdescribed in this disclosure. The processor may execute instructionsstored in computer memory accessible to the processor, or may employlogic implemented as field-programmable gate arrays (‘FPGAs’),application-specific integrated circuits (‘ASICs’), other combinatorialor sequential logic hardware, and so on.

One point of novelty of the system illustrated in FIG. 1A is that the atleast one processor may be configured to perform certain methods(discussed below) that are not in the prior art. A surface controlsystem or downhole control system may be configured to control the tooldescribed above and any incorporated sensors and to estimate a parameterof interest according to methods described herein.

Aspects of the present disclosure are subject to application in variousdifferent embodiments. In some general embodiments, the carrier isimplemented as a tool string of a drilling system, and the acousticwellbore logging may be characterized as “logging-while-drilling” (LWD)or “measurement-while-drilling” (MWD) operations.

FIG. 1B is a schematic diagram of an exemplary drilling system 101according to one embodiment of the disclosure. FIG. 1B shows a drillstring 120 that includes a bottomhole assembly (BHA) 190 conveyed in aborehole 126. The drilling system 101 includes a conventional derrick111 erected on a platform or floor 112 which supports a rotary table 114that is rotated by a prime mover, such as an electric motor (not shown),at a desired rotational speed. A tubing (such as jointed drill pipe122), having the drilling assembly 190, attached at its bottom endextends from the surface to the bottom 151 of the borehole 126. A drillbit 150, attached to drilling assembly 190, disintegrates the geologicalformations when it is rotated to drill the borehole 126. The drillstring 120 is coupled to a drawworks 130 via a Kelly joint 121, swivel128 and line 129 through a pulley. Drawworks 130 is operated to controlthe weight on bit (“WOB”). The drill string 120 may be rotated by a topdrive (not shown) instead of by the prime mover and the rotary table114. Alternatively, a coiled-tubing may be used as the tubing 122. Atubing injector 114 a may be used to convey the coiled-tubing having thedrilling assembly attached to its bottom end. The operations of thedrawworks 130 and the tubing injector 114 a are known in the art and arethus not described in detail herein.

A suitable drilling fluid 131 (also referred to as the “mud”) from asource 132 thereof, such as a mud pit, is circulated under pressurethrough the drill string 120 by a mud pump 134. The drilling fluid 131passes from the mud pump 134 into the drill string 120 via a desurger136 and the fluid line 138. The drilling fluid 131 a from the drillingtubular discharges at the borehole bottom 151 through openings in thedrill bit 150. The returning drilling fluid 131 b circulates upholethrough the annular space 127 between the drill string 120 and theborehole 126 and returns to the mud pit 132 via a return line 135 anddrill cutting screen 185 that removes the drill cuttings 186 from thereturning drilling fluid 131 b. A sensor S1 in line 138 providesinformation about the fluid flow rate. A surface torque sensor S2 and asensor S3 associated with the drill string 120 respectively provideinformation about the torque and the rotational speed of the drillstring 120. Tubing injection speed is determined from the sensor S5,while the sensor S6 provides the hook load of the drill string 120.

Well control system 147 is placed at the top end of the borehole 126.The well control system 147 includes a surface blow-out-preventer (BOP)stack 115 and a surface choke 149 in communication with a wellboreannulus 127. The surface choke 149 can control the flow of fluid out ofthe borehole 126 to provide a back pressure as needed to control thewell.

In some applications, the drill bit 150 is rotated by only rotating thedrill pipe 122. However, in many other applications, a downhole motor155 (mud motor) disposed in the BHA 190 also rotates the drill bit 150.The rate of penetration (ROP) for a given BHA largely depends on the WOBor the thrust force on the drill bit 150 and its rotational speed.

A surface control unit or controller 140 receives signals from thedownhole sensors and devices via a sensor 143 placed in the fluid line138 and signals from sensors S1-S6 and other sensors used in the system101 and processes such signals according to programmed instructionsprovided to the surface control unit 140. The surface control unit 140displays desired drilling parameters and other information on adisplay/monitor 141 that is utilized by an operator to control thedrilling operations. The surface control unit 140 may be acomputer-based unit that may include a processor 142 (such as amicroprocessor), a storage device 144, such as a solid-state memory,tape or hard disc, and one or more computer programs 146 in the storagedevice 144 that are accessible to the processor 142 for executinginstructions contained in such programs. The surface control unit 140may further communicate with a remote control unit 148. The surfacecontrol unit 140 may process data relating to the drilling operations,data from the sensors and devices on the surface, data received fromdownhole, and may control one or more operations of the downhole andsurface devices. The data may be transmitted in analog or digital form.Thus, surface control unit 140 is analogous in many ways to system 89,as described in FIG. 1A.

The BHA 190 may also contain formation evaluation sensors or devices(also referred to as measurement-while-drilling (“MWD”) orlogging-while-drilling (“LWD”) sensors) determining resistivity,density, porosity, permeability, acoustic properties, nuclear-magneticresonance properties, formation pressures, properties or characteristicsof the fluids downhole and other desired properties of the formation 195surrounding the BHA 190. Such sensors are generally known in the art andfor convenience are generally denoted herein by numeral 165, and includecounterparts to sensors described above with respect to FIG. 1A. The BHA190 may further include a variety of other sensors and devices 159 fordetermining one or more properties of the BHA 190 (such as vibration,bending moment, acceleration, oscillations, whirl, stick-slip, etc.),drilling operating parameters (such as weight-on-bit, fluid flow rate,pressure, temperature, rate of penetration, azimuth, tool face, drillbit rotation, etc.). For convenience, all such sensors are denoted bynumeral 159.

The BHA 190 may include a steering apparatus or tool 158 for steeringthe drill bit 150 along a desired drilling path. In one aspect, thesteering apparatus may include a steering unit 160, having a number offorce application members 161 a-161 n. The force application members maybe mounted directly on the drill string, or they may be at leastpartially integrated into the drilling motor. In another aspect, theforce application members may be mounted on a sleeve, which is rotatableabout the center axis of the drill string. The force application membersmay be activated using electro-mechanical, electro-hydraulic ormud-hydraulic actuators. In yet another embodiment the steeringapparatus may include a steering unit 158 having a bent sub and a firststeering device 158 a to orient the bent sub in the wellbore and thesecond steering device 158 b to maintain the bent sub along a selecteddrilling direction. The steering unit 158, 160 may include near-bitinclinometers and magnetometers.

The drilling system 101 may include sensors, circuitry and processingsoftware and algorithms for providing information about desired drillingparameters relating to the BHA, drill string, the drill bit and downholeequipment such as a drilling motor, steering unit, thrusters, etc. Manycurrent drilling systems, especially for drilling highly deviated andhorizontal wellbores, utilize coiled-tubing for conveying the drillingassembly downhole. In such applications a thruster may be deployed inthe drill string 190 to provide the required force on the drill bit.

Exemplary sensors for determining drilling parameters include, but arenot limited to drill bit sensors, an RPM sensor, a weight on bit sensor,sensors for measuring mud motor parameters (e.g., mud motor statortemperature, differential pressure across a mud motor, and fluid flowrate through a mud motor), and sensors for measuring acceleration,vibration, whirl, radial displacement, stick-slip, torque, shock,vibration, strain, stress, bending moment, bit bounce, axial thrust,friction, backward rotation, BHA buckling, and radial thrust. Sensorsdistributed along the drill string can measure physical quantities suchas drill string acceleration and strain, internal pressures in the drillstring bore, external pressure in the annulus, vibration, temperature,electrical and magnetic field intensities inside the drill string, boreof the drill string, etc. Suitable systems for making dynamic downholemeasurements include COPILOT, a downhole measurement system,manufactured by BAKER HUGHES, a G.E. Company, LLC.

The drilling system 101 can include one or more downhole processors at asuitable location such as 193 on the BHA 190. The processor(s) can be amicroprocessor that uses a computer program implemented on a suitablenon-transitory computer-readable medium that enables the processor toperform the control and processing. The non-transitory computer-readablemedium may include one or more ROMs, EPROMs, EAROMs, EEPROMs, FlashMemories, RAMs, Hard Drives and/or Optical disks. Other equipment suchas power and data buses, power supplies, and the like will be apparentto one skilled in the art. In one embodiment, the MWD system utilizesmud pulse telemetry to communicate data from a downhole location to thesurface while drilling operations take place. While a drill string 120is shown as a conveyance device for sensors 165, it should be understoodthat embodiments of the present disclosure may be used in connectionwith tools conveyed via rigid (e.g. jointed tubular or coiled tubing) aswell as non-rigid (e. g. wireline, slickline, e-line, etc.) conveyancesystems. The drilling system 101 may include a bottomhole assemblyand/or sensors and equipment for implementation of embodiments of thepresent disclosure on either a drill string or a wireline.

Control of these components may be carried out using one or more modelsusing methods described below. For example, surface processor 142 ordownhole processor 193 may be configured to modify drilling operationsi) autonomously upon triggering conditions, ii) in response to operatorcommands, or iii) combinations of these. Such modifications may includechanging drilling parameters, mud parameters, and so on. Control ofthese devices, and of the various processes of the drilling systemgenerally, may be carried out in a completely automated fashion orthrough interaction with personnel via notifications, graphicalrepresentations, user interfaces and the like. Additionally oralternatively, surface processor or downhole processor may be configuredfor the creation of the model. Reference information accessible to theprocessor may also be used.

In some general embodiments, surface processor 142, downhole processor193, or other processors (e.g. remote processors) may be configured tooperate the well logging tool 110 to make well logging measurements.Each of these logical components of the drilling system may beimplemented as electrical circuitry, such as one or more integratedcircuits (ICs) operatively connected via a circuit board in accordancewith techniques of the present disclosure. Each of these control systemsmay be controlled by actors, such as a remote well operation controlhost having an operational control relationship established with thedrill string.

FIG. 2 illustrates a system for remote well logging in accordance withembodiments of the present disclosure. System 200 includes a local welllogging data acquisition management system 289 at the logging site(e.g., local control system), a plurality of remote well logging dataacquisition management systems 260 a, 260 b . . . 260 n located atremote locations from the local well logging data acquisition managementsystem 289, several wide area networks (WANs) for networkedcommunication, and a satellite system 264 for dedicated communications.

The local well logging data acquisition management system 289 may be inpart a legacy well logging system. System 289 may include a dataacquisition system 288 configured to communicate directly with the tool10 over a data communications cable (e.g., armored wireline cable 14) inways well known in the art, as well as communications system 262,display 292, input device 294 (e.g., keyboard, mouse, etc), and localdata storage 296.

The data acquisition system 288 may include a line control panel and aninterface 284. The data acquisition system 288 receives raw logging datafrom the logging tool 10 via the cable 14 and passes the data to theinformation processing system 290, which may be implemented as aspecially configured industrial computer. The data acquisition system288 is also configured to receive operational commands from theinformation processing system 290 and to pass the operational commandsto the logging tool 10.

The information processing system 290 is configured to receive commandsfrom remote well logging data acquisition management systems 260 a, 260b . . . 260 n and to control operation of the logging tool 10 inresponse to the commands, as well as cooperating with remote welllogging data acquisition management systems 260 a, 260 b . . . 260 n tostore data remotely, including generation of control signals to inducethe communications system 262 to transmit communication signals carryingthe acquired raw logging data.

The information processing system 290 is also configured to carry outother processes at the well site, including presentation ofrepresentations of raw logging data on display 292, processing of rawlogging data according to one or more algorithms to estimate parametersof interest, performing diagnostic tests on components of the system,generation of control signals to induce the power supply 282 to toggleand adjust the supply of power to the logging tool 10 (includingcessation of supplying power to the logging tool), and generation ofcontrol signals to control movement of the hoist 250 (e.g., to move thetool 10 to a predetermined position, to begin the movement of a loggingrun, to increase or decrease tension, etc.). The information processingsystem 290 may also be configured to store logging data in local storage296, to monitor conditions of WANs and satellite transmissions, and tocarry out methods of the present disclosure as described in furtherdetail below.

Each of the remote well logging data acquisition management systemsexecutes its own instance of a remote well operation control host, andthe local well operation control host is running on the local welllogging data acquisition management system 282, as discussed in greaterdetail with reference to FIG. 3.

Each of the remote well logging data acquisition management systems 260a, 260 b . . . 260 n is configured for transmitting well-loggingcommands to the local well logging data acquisition management system289 as digital communication signals on a WAN or the satellite system264 to the well logging data acquisition management system 289, in orderto control a first logging instrument 10 a, a second logging instrument10 b, or a conveyance device (e.g., cable hoist 250). The remote welloperation control host running on information processing system 270 ofsystems 260 a . . . 260 n is also configured to receive data via thelocal well operation control host on the corresponding well logging dataacquisition management system at the logging site so as to mirror rawwell logging data (from instruments on the tool 10 and acquired by thelocal well operation control host) to local storage 271. Representationsof mirrored data may be presented to a remote well operator on a display272, and remote subject matter experts at each of the remote welllogging data acquisition management systems 260 a, 260 b . . . 260 n maycontrol operations of one of the corresponding instrument by specifyingcommands using an input device 274 (e.g., keyboard, mouse, etc.).

The information processing system 270 is configured to allow an operatorto specify one or more commands (e.g., well operation commands) insubstantially real-time in dependence upon raw well logging datareceived in substantially real-time. The logging data may comprisesubstantially all the raw well logging data from a particular process(e.g., test), instrument, or substantially including all the raw welllogging data acquired locally (including all the raw well logging datatransmitted uphole from the tool(s)). A command may comprise anyinstruction (e.g., input value, or selected value) for controlling welloperations at the logging site, including, for example, operation of thelogging tool, the hoist device, or the power supply. For example,commands may comprise one or more of the following: (i) an instructionto perform measurement of a specific geological or down hole parameter,(ii) an instruction to actuate a device in the logging tool, (ii) aninstruction for moving the logging tool from a first position, (iii) aninstruction for applying power to the logging tool or to the hoistdevice, (iv) an instruction for removing power from the logging tool orfrom the hoist device, (v) an instruction for modifying measurementparameters utilized by the logging tool and (vi) an instruction forperforming a diagnostic test on a computer or the logging tool.

Networked and non-networked communications between well site and remotesites, as well as data acquisition, may be conventionally conducted. Seefor example, U.S. Pat. No. 7,305,305 to Beeson, U.S. Pat. No. 7,672,262to McCoy et al., U.S. Pat. No. 6,046,685 to Tubel, U.S. Pat. No.6,980,929 to Aronstam et al., and U.S. Pat. No. 5,959,547 to Tubel etal., each commonly owned with the present application and incorporatedherein by reference in its entirety. See also U.S. patent applicationpublication No.: US 2007/0237402 to Dekel et al., U.S. Pat. No.6,842,768 to Shaffer et al., and U.S. Pat. No. 6,139,197 to Banks.

In one example, the plurality of remote well logging data acquisitionmanagement systems 260 a, 260 b . . . 260 n are located onshore and thelocal control system 262 can be located on a drilling or production oilrig located offshore. Alternatively, the plurality of remote welllogging data acquisition management systems 260 a, 260 b . . . 260 n maybe at locations not visible from the local control system 262, such asin different states or countries.

FIG. 3 illustrates a distributed software architecture in accordancewith embodiments of the present disclosure. The system 300 includes alocal well operation control host 307 on a corresponding well loggingdata acquisition management system 305 at the logging site, and aplurality of remote well operation control hosts 312, 322, 332instantiated and operating on corresponding remote well logging dataacquisition management systems 310, 320, 330, respectively. Eachinstance includes a configurations file 304, 314, 324, 334 withinformation pertaining to particular instruments, tools, infrastructure,formation, local conditions, operations to be conducted, and so on. Theconfigurations file may be modified at any of the local well operationcontrol host 307 or the plurality of remote well operation control hosts312, 322, 332 by interaction with personnel at the system or throughautomated control in response to detected conditions. Each instance alsoincludes links to locally stored copies of raw logging data 304, 314,324, 334. Each remote well logging data acquisition management system310, 320, 330 may be specifically configured to conduct operations withrespect to particular instruments or logging operations (e.g., services)conducted on a particular instrument, in effect configuring the systemsas instrument (or service) control centers.

A first remote well logging subject matter expert(s) 351 may interactwith remote well operation control host 312 to conduct well operationsrelating to a first instrument. For example, the subject matter expert351 may be a nuclear physicist conducting gamma ray spectroscopy. Thelocal well operation control host or the remote well operation controlhost may bin recorded gamma rays as a function of the voltage level eachgamma ray generates in the measurement instrument. The recorded gammaray spectrum may then be provided as a function of the channels. Thechannels in the abstract are not meaningful for gamma ray spectroscopyapplications, but become useful if they converted to a representation interms of energy. Thus, the physicist may map spectra recorded in termsof channels into spectra expressed in terms counts with respect toenergy, by finding the relevant peaks with known energy levels and thengenerating a transfer function based on what channel those peaks arelocated. The physicist may adjust the gain, gate timing, or othervariables of radiation detectors downhole during the measurementoperations.

A second remote well logging subject matter expert(s) 352 may interactwith remote well operation control host 322 to conduct well operationsrelating to a second instrument. For example, the subject matter expert352 may be a resistivity imaging specialist. The specialist may adjustinstrument operations, for example, to correct for invasion and shoulderbeds, dip, anisotropy, and effects of surrounding beds.

Another remote well logging subject matter expert(s) 358 may interactwith remote well operation control host 332 to conduct well operationsrelating to a third instrument. For example, the subject matter expert358 may be a borehole acoustic specialist. The specialist may optimizethe output power of an acoustic wavetrain emitted from a transducerrotatably mounted in a downhole borehole televiewer for scanning thesidewall of the borehole, in order to prevent destructive interferencebetween the caudal portion of the outgoing wave train and the returningecho signals from the borehole sidewall. This may be accomplished bydiscretely controlling the amplitude level of the excitation voltageapplied to the acoustic transducer.

In embodiments, each of the remote well operation control hosts may beconfigured to receive all or portions of the raw logging data for allthe instruments at the well site. Logging data from additionalinstruments are often helpful, and in some circumstances may becritical, in adjusting an instrument or interpreting results. In someimplementations, the amount of data received from the other instrumentsmay be determined in dependence upon data transfer characteristics ofthe network, as described in further detail below. Optionally, a masterremote well operator 359 may coordinate control of the instruments andthe conveyance device by each of the subject matter experts, eitherthrough permissions, or communications to each well operation controlhost.

FIG. 4 illustrates methods of remote well logging in accordance withembodiments of the present disclosure. Method 400 may includeconducting, with a plurality of remote well operation control hostsoperating on corresponding remote well logging data acquisitionmanagement systems, a well logging operation using a well logging systemat a logging site, wherein the well logging system includes a conveyancedevice having disposed thereon a first logging instrument and a secondlogging instrument.

Step 405 of method 400 may comprise establishing an operational controlrelationship. This may include establishing an operational controlrelationship between the carrier and a first remote well operationcontrol host sufficient for the first remote well operation control hostto control the carrier responsive to at least one well-logging commandfrom the first remote well operation control host; establishing anoperational control relationship between one or more logginginstrument(s) and a second remote well operation control host of theplurality; establishing an operational control relationship between oneor more logging instrument(s) and a plurality of remote well operationcontrol hosts; or combinations of these. The operational controlrelationship is sufficient for the second remote well operation controlhost to control the at least one logging instrument responsive to atleast one well-logging command from the second remote well operationcontrol host. Establishing operational control relationships isdescribed in further detail herein below.

Step 410 of method 400 may comprise conveying a first well logginginstrument and a second well logging instrument in a borehole using aconveyance device, such as, for example, a tool supported by a wirelinecable. Step 420 may comprise operating the first logging instrumentresponsive to at least one well-logging command from a first remote welloperation control host of the plurality; and step 430 may compriseoperating the second logging instrument responsive to at least onewell-logging command from a second remote well operation control host ofthe plurality different than the first. Operating the instruments mayinclude, for example, changing a setting on the instrument which affectscharacteristics of the well logging data produced. In one example, again setting of the instrument may be increased or decreased to improveaccuracy, resolution, and so on.

Step 440 may comprise acquiring raw well logging data from the firstlogging instrument and the second logging instrument by a local welloperation control host on a corresponding well logging data acquisitionmanagement system at the logging site, such as, for example by using thesystem architecture described in greater detail above. Step 450 maycomprise mirroring the acquired raw well logging data to at least one ofthe plurality of remote well operation control hosts in substantiallyreal time.

In some cases, maximum data resolution or substantially maximum dataresolution raw data is needed for analysis of a logged volume. Maximumdata resolution refers to the highest sampling speed of the instrumentwhich may be received at the local LDAMS from the tool in substantiallyreal time. Substantially maximum data resolution refers to a datatransmission rate for raw tool data at least 95 percent of the maximumdata resolution rate. Due to the voluminous nature of substantiallymaximum data resolution raw data, the tenuous nature of communicationsover portions of the WAN for particular well sites, and thesubstantially real-time specifications for this step, raw logging dataand system status/controls may be recorded in several local and remotecomputers and system components may be configured with failoverprocedures to ensure continuous operation with no data loss undercommunication interruptions or equipment malfunctions, as described infurther detail below. This may be carried out in part by synchronizingthe plurality of remote well operation control hosts with the local welloperation control host. The logging data at the local well operationcontrol host may be processed identically and in parallel with thelogging data at the plurality of remote well operation control hosts andmay maintain mirrored sets of control data.

Step 460 may comprise issuing a further command from at least one of theplurality of remote well operation control hosts responsive to theacquired raw well logging data. Methods may include using the loggingdata to control the logging operation with at least one second commandin substantially real-time from the at least one of the plurality ofremote well operation control hosts responsive to the logging datareceived. Step 470 may comprise changing the operation of at least oneof the first instrument, the second instrument, and the conveyancedevice responsive to receiving the further command. The further commandmay result in toggling an instrument on or off, adjusting gain,adjusting gate settings, adjusting the length of time a tool isenergized, reclogging a section of the wellbore, or (in the case of MWDtools) may result in steering the path of the drill bit, stoppingdrilling, and so on.

FIGS. 5A-5D illustrate systems for remote well logging in accordancewith embodiments of the present disclosure. Referring to FIG. 5A, system500 includes a local well logging data acquisition management system 502at the logging site (e.g., local control system), a plurality of remotewell logging data acquisition management systems 560 a, 560 b, 560 c,560 d located at remote locations from the local well logging dataacquisition management system 502 and several wide area networks (WANs)for networked communication.

The local well logging data acquisition management system (local LDAMS)502 may include local data storage 504. Local LDAMS 502 executes aninstance of a local well operation control host 506 for acquisition ofwell logging data from the well site infrastructure and storage of rawlogging data in local data storage 504, connecting with remote welloperation control hosts as described above for remote control of logginginstruments, and mirroring the raw logging data from local storage toremote well operation control hosts 566 in substantially real time. Thelocal well operation control host 506 may also be configured to monitorconditions of WANs and satellite transmissions, and to carry out methodsof the present disclosure as described in further detail below. Each ofthe remote well logging data acquisition management systems 560 a, 560b, 560 c, 560 d is executing its own instance of a remote well operationcontrol host 566 a, 566 b, 566 c, 566 d.

Functionality and responsibilities of various remote well operationcontrol hosts may vary within a system. A first remote well operationcontrol host 566 a may function as a master remote well operationcontrol host, which may control carrier operation and assign control ofinstruments or other logging infrastructure to other remote welloperation control hosts 566 b, 566 c, 566 d, etc. In some examples,logging data and/or commands may be routed through the remote welllogging data acquisition management system 560 a associated with themaster remote well operation control host 566 a, where the data may bestored and distributed to the other remote well operation control hosts566 b, 566 c, 566 d, such as, for example, through a LAN connecting theother remote well logging data acquisition management systems 560 b, 560c, 560 d to the first remote well logging data acquisition managementsystems 560 a (and possibly each other). In other examples, each remotewell operation control host 566 a, 566 b, 566 c, 566 d may be fullynetwork connected.

Each of the remote well operation control hosts 566 a, 566 b, 566 c, 566d may have a unique function. Example techniques in accordance withembodiments of the present disclosure may include conveying theconveyance device to intersect a volume of interest relating to thefirst logging instrument via tool commands from a first of the pluralityof remote well operation control hosts. Upon the device intersecting thevolume of interest, control of the conveyance device may then beassigned from the first of the plurality of remote well operationcontrol hosts to a second of the plurality of remote well operationcontrol hosts. Thus, a team of specialists trained and experienced infinding the volume of interest may operate from a first remote welllogging data acquisition management system 560 a utilizing a firstremote well operation control host 566 a, while individual welloperations engineers specializing in measurement operations with theinstruments may each operate from other remote well logging dataacquisition management systems 560 b, 560 c utilizing a specificcorresponding remote well operation control host 566 b, 566 c. In oneexample, infrequent and delicate operations, such as, for example, atool becoming stuck in the wellbore, may be delegated to a contingencyunit 560 d (which may utilize a specially configured remote welloperation control host 566 d), where specialists in contingency actionsmay alleviate the condition (e.g., a stuck condition of the tool string,kick detection, etc.). Alternatively, control may automatically revertto the local well operation control host 506.

During a logging operation, the local well operation control host 506operates to transmit substantially all raw well logging data generatedby the instruments from the logging site to at least one of theplurality of remote well operation control hosts over a WAN. The localand remote well hosts cooperatively use the logging data to control thelogging operation with at least one second command in substantiallyreal-time from the at least one of the plurality of remote welloperation control hosts responsive to the logging data received. Aspectsof the cooperative functionality of the local and remote hosts areimplemented to remedy difficulties arising from the specific context ofsubstantially real-time remote well logging. Connectivity issues makereal-time remote well logging problematic. Connectivity issues are alsoendemic to many of the areas in which remote well logging may beemployed. Thus, gracefully handling connectivity issues resulting ininsufficient data transfer during remote well operations is critical toproviding real-time control of well logging operations.

For example, systems of the present disclosure may implement contingentoperational modes to provide failover. Local well operation control host506, for instance, may determine a value for at least one data transfercharacteristic of the WAN with respect to the at least one of theplurality of remote well operation control hosts. Example data transfercharacteristics may include metrics corresponding to throughput,downtime, failures, and the like. Local well operation control host 506may conduct a comparison of the value for the at least one data transfercharacteristic with at least one operational sufficiency profile. Thecontingent operational mode may be implemented in dependence upon thecomparison. In other examples, contingency protocols may be implementedfor non-data transfer contingencies, such as, for example, emergencyconditions as detected from sensor information.

Each operational sufficiency profile may be representative of datatransfer characteristic values indicating data transfer sufficient forcontrol of the logging operation in substantially real-time to astandard equal to conventional on-site control. Heuristics, rules,ranges, or thresholds may be used. As one example, if average throughputfalls below a first threshold rate for a period of time exceeding asecond threshold duration, a contingent operational mode may betriggered. The contingent operational mode may include, for example, i)reducing logging speed; ii) storing logging information at another node;iii) ceding operational control of a logging instrument to a welloperation control host local to the logging site; iv) ceding operationalcontrol of the carrier to a well operation control host local to thelogging site; vi) ceding operational control of a logging instrument toanother node; vii) ceding operational control of the carrier to anothernode; viii) repeating a logging interval; and ix) implementing a changein data compression schemes. Changes in compression schemes may becarried out using a variety of techniques.

In some examples, the implemented contingent operational mode may beselected from a plurality of available contingent operational modes froma configurations file. In embodiments, the contingent operational modemay be implemented in dependence upon an order of priority of at leastone of logging data from each logging instrument or operations betweeneach logging operation associated with a particular logging instrument.For example, data from instruments or processes having a lower prioritymay be pre-compressed prior to compression of the general data stream,or in some cases may be suspended altogether. Priority and criticalitydata may be stored as a configurations file, determined usingheuristics, and so on.

As data transfer slows, receipt of logging data corresponding to one ormore services may fall behind real-time. Catch-up of a particular streamof data may be moved up or down in priority (e.g., expedited or delayed,respectively), or forgone in lieu of more recent data, in accordancewith the current operational mode. As an example, data from a secondaryoperation may be cached, and particular segments transmitted whencorrelated with a segment of interest corresponding to data from anotherinstrument. In some examples, snapshots of downgraded data streams maybe forwarded at intervals to conserve bandwidth.

In some instances a proxy (not shown) operating at the well site (e.g.,executing on an information processing device shared by the local welllogging host or on a system locally networked to the informationprocessing device) is configured to receive commands from remote welloperation control hosts 566 a, 566 b, 566 c, 566 d and to controloperation of the logging tool 10 in response to the commands.

FIG. 5B illustrates another system for remote well logging in accordancewith embodiments of the present disclosure. Embodiments described hereinabove include implementations wherein remote sites are each connectedthru individual WAN links directly to the local logging data acquisitionmanagement system. However, in some operations, WAN links having broadbandwidths at high reliability (e.g., characteristic to WANs found in atypical city) may not be available.

System 570 features a local logging data acquisition management system572 connected to a first remote logging data acquisition managementsystem 574, along with additional remote logging data acquisitionmanagement systems 576 a . . . 576 n connected directly to the firstremote logging data acquisition management system 574. In this case, thefirst remote logging data acquisition management system 574 may belocated within a city where reliable large bandwidth networks arecommonly available. The first remote logging data acquisition managementsystem 574 may include a first remote well operation control host 580which may function as a master remote well operation control hostsimilarly to first remote well operation control host 566 a (FIG. 5A).This reduces the multi-channel requirements for the local logging dataacquisition management system 572 but increases the bandwidthrequirements of the WAN link between the first remote logging dataacquisition management system 574 and the local logging data acquisitionmanagement system 572. To provide the desired degree of redundancyadditional WAN links (not shown) could be added in parallel between thefirst remote logging data acquisition management system 574 and thelocal logging data acquisition management system 572. Thus, system 570includes multi-channel WAN capabilities of the local logging dataacquisition management system while providing redundancy links useful ascontingency data paths should some of the links become interrupted.

As described in greater detail with respect to FIG. 3 above, each remotewell logging data acquisition management system may be specificallyconfigured to conduct operations with respect to particular instrumentsor logging operations (e.g., services) conducted on a particularinstrument in logging tool 578, in effect configuring the systems asinstrument (or service) control centers. Because each subject matterspecialist (or team of specialists) is freed from interacting withsubject matter not in his or her area of expertise, the specialist isavailable to work on other well sites.

FIG. 5C illustrates another system for remote well logging in accordancewith embodiments of the present disclosure. In system 581, multiplelogging jobs at different well sites are effectively controlled frommultiple remote sites. Each of local logging data acquisition managementsystems 582 a . . . 582 n are connected to first remote logging dataacquisition management system 584 through individual WANs (WAN1 . . .WANn). In some implementations, multiple parallel WANs may be used toconnect any or all local logging data acquisition management systems 582a . . . 582 n to first remote logging data acquisition management system584. Additional remote logging data acquisition management systems 586 a. . . 586 n are connected directly to the first remote logging dataacquisition management system 584. The first remote logging dataacquisition management system 584 may include a first remote welloperation control host 590 which may function as a master remote welloperation control host similarly to first remote well operation controlhost 566 a (FIG. 5A). In any case, control of a particular subsystem,instrument, or logging operation with respect to a tool (588 a, 588 b .. . 588 n) connected to each of local logging data acquisitionmanagement systems 582 a . . . 582 n, respectively, may be distributedto the corresponding subject matter expert at the appropriate additionalremote logging data acquisition management system 586 a . . . 586 n.

In this configuration, one logging expert located in one of the remotesites (e.g., 586 a) controls a variety of tools (e.g., 588 a, 588 b . .. 588 n) which may be part of different tool strings being logged atmultiple well sites. Although FIG. 5C shows all data traffic passingthrough the first remote logging data acquisition management system 584,this configuration is only one of many possible configurations whichwill occur to those of skill in the art in light of the presentdisclosure, and the logging of multiple well sites may be incorporatedin any of the example systems described herein.

FIG. 5D illustrates another system for remote well logging in accordancewith embodiments of the present disclosure. In system 583, multiplelogging jobs at different well sites may be effectively controlled frommultiple remote sites. Each of local logging data acquisition managementsystems 592 a . . . 592 n and remote logging data acquisition managementsystems 596 a . . . 596 n are connected to a highly availabledistributed remote cluster 594, which may comprise one or more datacenters or cloud implementations. Distributed remote cluster 594 may beimplemented using multiple redundant computing resources in differentlocations. Clustered resources may be managed through a virtualizedmaster identity. Control of a particular subsystem, instrument, orlogging operation with respect to a tool (598 a, 598 b . . . 598 n)connected to each of local logging data acquisition management systems592 a . . . 592 n, respectively, may be distributed to the correspondingsubject matter expert at the appropriate additional remote logging dataacquisition management system 596 a . . . 596 n. That is, jobs may berouted to a particular system based upon subject matter independent ofthe well site the data originates from. Thus, jobs from a particularwell site may be parsed to operators at many locations, and an operatorat a particular location may receive jobs of the same subject matterfrom various well sites.

Enabling operation of a first logging instrument by the first remotewell operation control host and operation of a second logging instrumentby the second remote well operation control host may be carried out byusing the distributed remote cluster to distribute control capabilityfor a particular instrument to a particular remote well operationcontrol host, by transmitting well logging data from the instruments tothe particular remote well operation control host using the distributedremote cluster, and so on.

Although FIG. 5D depicts all data traffic from both ends passing thru adata Center or Cloud type of infrastructure, any possible combination ofdirect connections to the local wellsite systems, remote systems, anddata centers or cloud-based implementations may be employed.

FIG. 6 illustrates another system for remote well logging in accordancewith embodiments of the present disclosure. Surface and downholeinstruments and sensors 1 . . . n 622 provide data to data acquisitionsystems 1 . . . N 620 tailored to interface with correspondingparticular tools and data. Data acquisition management system 630 storesdata with local system 610 and provides for mirroring the data throughcommunications management system 614 to remote data acquisitionmanagement system 612 which stores data to its own local storage andprocessing system on a network local to the remote data acquisitionmanagement system 612. Data acquisition management system 630 alsointerfaces with hoist device display unit 640.

System 600 further includes enhanced functionality implemented throughspecialty components. System 600 is configured to use a digitalrecording system 642 including a digital video camera and associatedmicrophone to transmit with communications management system 614 avirtual presence feed during a logging operation using a Wide AreaNetwork (WAN). The virtual presence feed may include, for example, videoinformation, audio information, gps information, and the like associatedwith a logging site supervisor from the logging site to at least one ofthe corresponding remote well logging data acquisition managementsystems 612. The digital recording system 642 may be incorporated aspart of a virtual presence device 644. In some instances, the virtualpresence device may be implemented as a personal presence devicewearable by the logging site supervisor or other personnel (virtualpresence persons 646) or otherwise portable or perspective dependent.

The remote data acquisition management system and/or the remote dataacquisition control, recording and processing system may use the virtualpresence feed to construct a representation of a virtual presenceperspective (e.g., similar to a virtual tour) of the position of thelogging site supervisor at the logging site, and present therepresentation to a remote well operating engineer at the at least oneof the corresponding remote well logging data acquisition managementsystems. In this way, the remote well operating engineer may be able tovirtually “stand in the shoes” of the logging site supervisor at thewell site. The ability to faithfully recreate visual and auditory cuespresent at the well site to the remote well operating engineer allowsthe remote engineer to make faster and more accurate operationsdecisions based on experience in legacy operations on site.

System 600 may also, during the logging operation, use the Wide AreaNetwork (WAN) to transmit audio instruction data and auxiliary data fromthe remote well logging data acquisition management system 612 to thelogging site. The communications management system 614 (oralternatively, the data acquisition management system 630) may renderthe audio instruction data as audio instructions via a personalcommunication system of the logging site supervisor, and render theauxiliary data on a graphic interface of the personal communicationsystem of the logging site supervisor. In this way, the personnel at thewell site may be used as a virtual extension of the remote welloperating engineer. The remote well operating engineer may make use ofthe sensory and motion ability of the local personnel through live audiovisual contact in order to execute key manual tasks remotely. The audioinstruction data may be streamed audio from the well operation engineeror standardized instructions, such as, for example, instructions relatedto alert conditions or emergencies. Auxiliary data may includestep-by-step instructions, excerpts from manuals, maps, simulatedcontrol interfaces including guidance indicia, speech-to-texttranscripts of the audio, and so on. The simulated control interface mayshow added text, flags, coloration, or blinking lights to indicate whichpart of the interface should be interacted with. Auxiliary data may alsobe overlain on a video feed to provide guidance in a virtualthree-dimensional space.

FIGS. 7A-7C illustrate a virtual presence system for incorporation insystem embodiments in accordance with the present disclosure. FIG. 7Aillustrates virtual presence system components in use at a remote dataacquisition management system. The system includes a digital webcamfocusing on a first well logging operator 702, who can view video andinformation from a logging site supervisor (see FIG. 7B, 711) on adisplay 703, and hear audio on surround speaker system 704. A secondwell logging operator 705 wears a virtual reality visor 707 andheadphones rendering the representation of a virtual presenceperspective of the position of the logging site supervisor at thelogging site.

FIG. 7B illustrates a personal communication system of the logging sitesupervisor. The personal communication system 710 includes a heads-updisplay 713, an eye-level camera 712 corresponding to the field ofvision of the logging site supervisor 711, and headphones 714. Thepersonal communication system 710 also includes a wearable microphone715 which may be attached to a lanyard or shirt.

FIG. 7C illustrates a view of the logging site supervisor 711 on theheads-up display 713 of the personal communication system 710. Theheads-up display 720 renders graphical elements on a live videopresented on a view screen or on live view through a transparent lens.The graphical elements include an inset video feed 729 of first welllogging operator 702, and auxillary data in the form of virtual paneloverlay 721, which includes a list of steps 722 and a simulated controlinterface 723 including guidance indicia in the form of label 724 andblinking light overlay 725 indicating the physical button to be pressed,known as augmented reality. Fiducial markers applied to equipment mayallow an augmented reality system to overlay virtual graphics withinstructions over the view.

Audiovisual data and graphical modification of video feeds may beconventionally conducted. See for example, U.S. Pat. No. 9,569,097 toRamachandran, U.S. Pat. No. 6,223,206 to Dan et al., and U.S. Pat. No.5,689,641 to Ludwig et al, and U.S. patent application no. 2017/0249745to Fiala, each incorporated herein by reference.

Well operations comprise a collection of operational processes relatedto actions or equipment at the local well site. For example, trippingthe well may be accomplished through a series of operational processesincluding actuation of the winch, output of data from depth sensors,strain sensors, and the like, polling of sensors downhole, and so on.Likewise, drilling processes may include optimizing drilling dynamics bycontrolling rate of penetration, RPM, weight on bit, and other drillingparameters by direct actuation or issuing of control directives,notifications, or alarms in dependence upon output from sensorsrepresentative of these parameters. Optimizing a mud program, oroperation of particular formation evaluation instruments, may besimilarly carried out via a collection of operational processes.

Many processes are typically related to one another. If two processeshave no relation, they be said to be mutually exclusive. Otherrelationships may include sequential relationships, dependentrelationships, co-dependent relationships, subordinate relationships,simultaneous relationships, and so on.

The operational processes may be carried out by actors in a controlsystem. Actors may include a computer system, a processor, personnel,and the like. An actor is responsible for operational processes assignedto it. An operational process may also require association of privilegesto the actor which enable the actor to carry out the operationalprocess. In a distributed system, various remote actors may haveinterest in a process. The distribution of control of the process to oneor more actors, and the allocation of resources to various processesand/or actors is significantly more challenging than in conventionalremote logging scenarios.

Aspects of the present disclosure include establishing an operationalcontrol relationship between the carrier and a remote well operationcontrol host sufficient for the remote well operation control host tocontrol the carrier responsive to at least one well-logging command fromthe first remote well operation control host. In some instances, morethan one remote well operation control host may have this relationship(and thus, control the carrier) at various points in time. Bycontrolling the carrier, it is meant that the movement of the carrier iscontrolled through various processes.

Aspects of the present disclosure include establishing an operationalcontrol relationship between selected ones of the at least one logginginstrument disposed on the carrier and a remote well operation controlhost of the plurality, the operational control relationship sufficientfor the remote well operation control host to control the at least onelogging instrument responsive to at least one well-logging command fromthe remote well operation control host. This remote well operationcontrol host may be different than the remote well operation controlhost controlling the carrier. Aspects may additionally includeestablishing an operational control relationship between selected onesof the at least one logging instrument disposed on the carrier andvarious remote well operation control hosts, such that two hosts maysplit time or functionality on a single instrument, and/or a single hostmay control a plurality of instruments.

In accordance with techniques of the present disclosure, control of andresponsibility for each of these operational processes may beimplemented by assigning the process to one or more actors andassociating privileges required to carry out the process with theseactors. Privileges enable control of a resource by the actor viacommands and/or access to data from a resource, including (in somecases) virtual presence data. A gateway limits access and control ofwell resources unless a particular actor has privileges to thoseresources.

In some cases, failover may be implemented by employing hierarchicalprivileges. In other cases, privileges may be dynamically assigned toone or more actors in a pool of actors to provide failover. As oneexample, actors may have credentials associated therewith in a database,and a control system may assign an operational process and grant accessto data and control of resources such as a system, component, orcomputer process (e.g, by establishing a control link, a controlsession, or other logical control paradigm) associated with theoperational process to at least one actor based on the operationalcredentials of the at least one actor.

Actors may be associated with roles to establish an operational controlrelationship with a resource. FIGS. 8A-8C illustrate the use of roles inestablishing control relationships. FIG. 8A illustrates a distributedcontrol framework in accordance with embodiments of the presentdisclosure. FIG. 8A shows a local distribution system L₀ 803 connectedto local data acquisition systems L₁ . . . L_(n) (804), e.g., over oneor more LANs. The local distribution system is connected to globalcontrol systems G₁, G₂ (801, 802) by a communication system (805), suchas, for example, the Internet. Master control 811 may also be connectedto global control systems 801, 802 and local distribution system 803 bycommunication system 805. Master control 811 may function as a type of“control tower” for operations at a regional or global level, and may beimplemented as master remote well operation control host (described ingreater detail above) controlled by a system administrator.

Well operations at wells corresponding to local data acquisition systemsL₁ . . . L_(n) (804) comprise a collection of processes related toactions or equipment at the wells stored as data structures in adatabase accessible to local distribution system 803. At least some ofthese processes are assigned to an actor by the local distributionsystem 803, or by a master control 811. Actors may include a firstglobal control system 801 and a second global control system 802, localdata acquisition systems, and the distribution system, as well aspersonnel at the wells. Local distribution system 803 may also functionas a gateway implementing control and data access. Local distributionsystem 803 implements this control and data access using a controlheuristic, as described in further detail below. In accordance withparticular embodiments, the control heuristic may be based on privilegesand constraints. Other control heuristics may employ context analysis,state analysis, or role analysis as described in greater detail below. Acontext may be maintained for each operational process comprising ahistory, a current state, and an objective. The context may also includerelated operational processes and the relationship. As one example, in anon-emergency situation, if the history of the process indicates controlhas been changed a threshold number of times, control change may berefused without additional authorization.

All global control systems available or interested in controllingprocesses at or receiving data from any or all of the wellscorresponding to local data acquisition systems L₁ . . . L_(n) (804) maytransmit an initiation message to the local distribution system 803notifying their respective status and/or intent. They may also discovereach other, and each may communicate to the others a status and intent.A heartbeat comprising a time stamp, globally unique identifier(‘GUID’), and status may be transmitted from each actor to thedistribution system and other actors (e.g., global control systems). Alisting of wells for each distribution system may be maintained in anetworked global database and associated with actors indicatinginterest.

The control heuristic may also incorporate one or more of role-basedcontrol and state-based control. A role represents a unique duty to theactor. A state indicates a set of conditions comprising a situationalrepresentation, and may apply to the actor, to the well, to the systemas a whole, and so on. The utilization of role-based control andstate-based control also allows for dynamic failover and load balancing.

Operational thresholds of a variety of types may be stored in adatabase, either based on particular instances of actors, or in relationto a class of actors. Each threshold may have an associated remedy. Asany one actor exceeds an operational threshold, the distribution systemimplements the remedy. As one example, if an operating engineer hasworked more than a threshold amount of time without a break, theoperational process assigned to him may be reassigned to anotherengineer at another workstation, and possibly at another remote workoperation control host. The role of the particular engineer and theparticular workstation replacing the operating engineer may be modifiedto grant privileges to carry out the assigned operational process.Associations between actors, roles, privileges and the like may beimplemented using various data structures and other techniques known inthe art, including databases, metadata, reference tables, pointers, andtags.

In some cases, control may be implemented by employing hierarchicalroles. In other cases, roles may be dynamically assigned to assign andtransfer control as needed. As one example, actors may have rolesassociated therewith in a database, and a control system may assign anoperational process and grant access to data and control of a system,component, or computer process associated with the operational processbased on the role. Roles may be shifted or modified in dependence upondetection of events, upon context, or by request from an actor or from amaster control. Some roles may have privileges to access data, withoutcontrol of the resource (e.g., an instrument). Some roles may havelimited control of the resource, while other roles may have universalcontrol of the resource. Roles may include control of relatedinstruments or of the movement of the tool string, or of mechanicaldevices downhole.

Likewise, some roles may receive one level of data access, while anotherrole receives a second, lesser or different level of data access. Forexample, the sampling rate of delivered instrument data, the bandwidthat which data is delivered, and the type of data delivered may all varywith respect to role.

Methods of well control operations in accordance with embodiments of thedisclosure may include implementation of a role based control structure.For example, a control system may assign an operational process andgrant access to data and control of a system, component, or computerprocess (e.g, by establishing a control link, a control session, orother logical control paradigm) associated with the operational processbased on roles. Roles may be associated with an actor.

Use of any service, system or component at the well, along with sharedservices such as power, position or velocity of the tool, bandwidth onthe system bus, or bandwidth on the WAN may be considered a resource.Methods of well operations control in accordance with embodiments of thedisclosure may include allocating control of well operations resources.This may be carried out by allocating at least one resource at a well toa process, distributed sharable resources to a plurality of processes,or allocating resources to a combination of process and remote actor.

A resource may have associated with it in a database, a configurationsfile, or the like, a set of one or more operational profiles. Theoperational profiles may be dependent upon (e.g., associated with) a setof current processes, actors associated with the processes, states, andso on. As one example, a bandwidth sharing profile for the modem of anexternal gateway of a remote logging data acquisition management systemmay indicate the bandwidth allotted to each process in fractional orabsolute terms (or a combination of the two) as a function of the activeprocesses and the total projected bandwidth available. When a newprocess is initiated, a logical rule may cause selection of analternative profile which deprecates the bandwidth allotted to theprevious processes and allots bandwidth to the new process in accordancewith the alternative profile. A higher priority level associated withthe new process than is associated with the previous processes mayresult in switching to a profile allotting a majority of the availablebandwidth to the new process.

FIGS. 9A & 9B illustrate control relationships between actors andresources. It should be noted that an actor may also be a resource. FIG.9A describes a functional block diagram for a winch process. The winchprocess is controlled locally by a local main box 901, which containsvarious functional modules such as an active operator 902, communication906, data storage 905, local control processor 903, local display 904,control bus 907, sensor input and output channels (I/O) 908, and autodefault setup. The winch system provides power and supportscommunication between the local main box 901 and the tool stringequipment via the deployment cable for example (or, alternatively, bycoiled tubing, pipe conveyed log, drill string, slick line, wireline, EMtelemetry, etc.).

The basic winch system functionality contains modules main power 924,power module 922, power sensors 921, power control 915, motor control916, motor 917, motor winch coupling 923, winch drum 918, and cablesensors 914. The local main box COMM module 906 provides communicationin conjunction with the cable communication module 909 for furthercommunication with the tool string equipment via the winch cable 919.The COMM module 906 communicates with the distributed network via theremote communication link network resources 910. The figure shows anexample of a distributed network connection with a remote virtual box925 which is a virtual mirror image of the local main box for remotelogging control and operations associated with distributed remote rolesand functions. The remote virtual box functional block diagram containsa remote operator 928, a COMM 930 and STORAGE module 931, remote controlprocessor 929, remote display 932, and is connected to a remote storagemodule 926 associated with a cloud-based distributed network storagesystem 927.

These distributed control systems associated with the local main box 901and remote virtual box 925 can each be controlled concurrently inmultiple ways by fully automated algorithms, by a man-machineinteractive semi-automated mode, or fully man-controlled operation.Control functions may be associate with multiple operational roles (e.g.rig operator, rig monitor, and so on) and corresponding tasks may beallocated to multiple actors. These actors-roles assignments arehierarchically controlled and may be implemented along with a controlswitch. The actors can be locally or remotely located. The remotelylocated roles can be organized into global, regional, areas and localgroups.

The role assignment process may establish an operational controlrelationship between processes and actors using an actor-roleassociation in a data structure, as shown in FIG. 9B. Actors 950 areassociated (dashed lines) with roles 960. Example roles include localrig operator (local) 961, rig monitor (local) 962, supervisor (area)963, monitor reporter (region) 964, administrator (master control) 965,remote operator (remote) 966. These roles are assigned to Actor 87(955), Actor 125 (957), Actor 2 (952), Actor 88 (956), Actor n−2 (958),and Actor n (959), respectively. Actor 1 (951), Actor 3 (951), and Actor4 (951), among others, are not assigned roles in this process. Theactor-role association can be carried out in dependence upon schedulingconstraints, such as, for example, an actor time schedule constraint,actor maximum task capacity workload allowed, role assignment expertiseand certification requirements, and so on.

Similarly, actors can be a component of a system (e.g., equipment) whichcan have its assignment shifted based on working conditions,availability, optimum equipment specifications, actor-to-role taskrequirements fit, project prioritization of tasks and goals, scheduleand safety optimization via equipment-to-actors assignments, etc. Eachof these characteristics may be parameterized and appropriate values ofthe parameters associated with actors, such as, for example, stored in arelational database as credentials. An actor (e.g., a remote welloperational control host) may be identified and selected for associationwith privileges in dependence upon a comparison of the credentials andthe credentials profile. It may include selecting the remote welloperational control host in dependence upon the comparison. This may becarried out using a selection heuristic, which may comprise a set ofselection rules. As one example, effective bandwidth of data transfer tothe remote host may be balanced against the experience rating in theparticular instrument or operation of the available personnel on duty atthe remote host, the availability of archived data at the remote host,technical specifications, and so on, in accordance with the credentialsprofile. Roles may be associated with a credentials profile. Theselection rules may be implemented as weighted combinations ofcredential values, stepwise logical decision trees, or other logicalrules. The selection rules may comprise part of the credentials profile.As one example, see the example decision rule rendered in pseudocodebelow.

Form Set1=ReturnAll ((Rhost:PING)=True)

Form Set2=ReturnGreatest (Set1:Experience:JobTag1132, 10)

Form Set3=ReturnAll ((Set1:Distance( ))<200)

Form Set4=ReturnAll ((Set1:EffBand( ))>1300)

IF ReturnTrue(Set2 AND Set3 AND Set4)=NOT %

Select (ReturnGreatest (Set1:Experience:JobTag1132, 1)

ELSE

Select (ReturnGreatest (Set1:EffBand( ))

The rule represented by the code above searches for all interestedremote hosts, then determines those having the top ten in experience atthe desired job. Another set of remote hosts is found within 200kilometers. Another set of remote hosts is created using bandwidth ofover 1.3 GHz. If any remote hosts are in each group, the ReturnTrue,will not return an empty set, and the remote host associated with thebest experience is selected. If no host is in all three groups, theinterested host having the highest effective bandwidth is selected.

FIG. 10 shows a flow chart illustrating an example of incorporation ofrole switching into a winch control operational process in accordancewith embodiments of the present disclosure. The winch starts itsoperational process (1002) and self-checks its health condition (1004).If there are operational health issues (1006) the winch operationprocess is aborted (1010). If the winch health is OK (1007) the winchproceeds to operation. Roles are initially assigned (1008) and the winchtakes a default wake-up state configuration (1012). The winch starts itsoperation (1014) and waits to receive a command. Whenever a command isreceived (1016) from an actor having privileges to the winch (e.g., bybeing associated with a role having privileges), the new command isactivated (1018) and the winch proceeds to its repetitive normaloperating loop executing the current command until completed or a newcommand is received (1018). Next the winch performs a report and sensorupdate (1020) and sends a report (1022) with its operational state, dataconditions, sensor data, and so on to nodes stored in a configurationsfile, e.g., to the network monitoring supervisory roles. Next the winchprocess checks for a role-actor assignment update (1024) for its controlfunctions. If a new control actor-role assignment is issued (1030) itsrole-actor connection algorithm is initiated, which may identify theavailability of the actor and the availability of the role in thepresent operational context. Upon capture of a new role-actorassignment, the old actor may be consulted if it can and will transferrole control (1032). If yes (1031) the process continues to consult withthe new actor and determines if and when the new actor is available, andif new actor can and will take role control (1034). If yes (1039),control handover is carried out, including verification the old actorhas transferred role control (1036) and the new actor has assumedcontrol (1038). If yes the new actor is confirmed to be in the new rolecontrol. If any of these four hand-shake verifications result in a NOthe new role-actor assignment is cancelled. Next, the winch state statusis verified (1026) and if the status check fails (1043), the winchprocess is aborted (1044) and shut down under a safe pre-definedprocedure. If the status check is positive (1045), the winch processcontinues to update its execution control sequence and operationconfiguration based on the role switch (1028), and then returns towaiting for a command update.

Returning to FIG. 8B, methods of well operations control in accordancewith embodiments of the disclosure may include allocating control of awell operations resource at a well by allocating at least one resourceto a remote actor in dependence upon a role associated with that actor.Roles 810 may be stored as data structures in a data base, and may beassociated with a credentials profile 811 representing the credentialsrequired to fulfil the role, a set of privileges 812 that are grantedwith the role, and a series of constraints 813 acting on the role. Therole data structure may be accessible (e.g., through operativeconnection to a local copy of a database) by the local distributionsystem 803. Actors may be associated with roles. Optionally, oralternatively, local distribution system 803 may allocate resources byusing actor based privileges 814, actor based constraints 815, sitebased constraints 816, well based constraints 817, equipment basedconstraints 818, personnel based constraints 819, and so on. The localdistribution system 803 may allocate resources based on a combination ofthese items by using heuristics comprising a collection of rules.

In some embodiments, well operations control (such as, for example, welllogging control, well drilling control, well casing installationcontrol, well stimulation control) may include allocating control of atleast one well operations resource at a well, comprising allocatingcontrol of the at least one well operations resource to a localcontroller while in a default state; and changing from the default stateby allocating control of the at least one well operations resource to aremote actor in dependence upon a role associated with the remote actor.The well operations resource may be a logging resource. This may includedetermining a state of the resource and/or a state of the logging site,and allocating the resource in dependence upon the role and thestate(s). In some cases, the credentials of an actor may be comparedagainst the credential profile of the role, either by distributionsystem 803 or master control 809, and a role may be dynamicallyassociated with the actor in dependence upon the comparison.

FIG. 8C shows a data flow diagram illustrating the communication betweenglobal control systems and a distribution system to change control of anoperational process over time. The process control is shown by the token860, which represents the role of operator. At a first time, T0, thedistribution system 803 has control of the operational process, and thusassumes the role of operator. At T1, a first global control system 801with appropriate credentials that is in contact with the distributionsystem 803 initiates a role switch with an initiation message 831 to thedistribution system. In some implementations, the message mayadditionally, or alternatively, be sent to a second global controlsystem 802 with appropriate credentials that is in contact with thedistribution system 803. The distribution system 803 assigns the role ofoperator to global control system 801 at T2 by sending assignmentnotification 832 to global control system 801 and assignmentnotification 833 to global control system 802. Global control system 801assumes command of the process in response to the message 832 at T3, andsends commands 834 and receives data 835, such as, for example,formation evaluation sensor data.

At T4, the second global control system 802 attempts to change roles toassume control of the process by sending a control request, which may bein the form of initiation message 836 to the distribution system 803. Insome schemes, the control request may take a different form than theinitiation message. The distribution system performs a handshakeprocedure to determine if the second global control system 802 make takecontrol. The handshake procedure may use a set of rules to determine anoutcome based on the role, the actors, related roles of the actors, thestate of the process or a related process (e.g., complete,mid-measurement, between measurements), equipment state (arm extended,tool position), constraints, and other priority information. The secondglobal control system 802 wins the handshake and distribution system 803assigns the role of operator to global control system 802 at T5 bysending assignment notification 837 to global control system 801 andassignment notification 838 to global control system 802. Global controlsystem 802 assumes command of the process in response to the message838, and sends commands 840 and receives data 841 at time T6.

Allocating resources may be carried out by triggering a rolemodification in response to detecting a role shift event; identifying atleast one actor associated with the role modification, and modifying therole of the at least one actor. Role shift events may include safetyalarms, equipment failure, kick detection, security breaches, loss ofconnection with the controlling actor (e.g., loss of heartbeat), a roleswitch initiation from an actor, a role switch initiation from mastercontrol, detection of a state linked with a particular actor not incontrol, detection of a state proscribed for the current actor, orcombinations of these. The role shift event may also be triggered byprocess activities dependencies and process activities constraints. Therole of the at least one actor may be modified to a new role includingprivileges to the resource. As one example, a role shift event maycomprise detection of the tool reaching a target volume of interest foran instrument on the tool string for which another actor has morecompatible or higher priority credentials.

At T7, a role shift event 842 is detected by distribution system 803,which triggers a role modification. In response to the detection,distribution system 803 sends a control offer 843 to global controlsystem 801 at T8. At T9, global control system 801 accepts the offer bysending a control accept message 844.

The distribution system 803 assigns the role of operator to globalcontrol system 801 at T10 by sending assignment notification 852 toglobal control system 801 and assignment notification 853 to globalcontrol system 802. Global control system 801 assumes command of theprocess in response to the message 852 at T11, and sends commands 854and receives data 855. When global control system 801 is finished it mayrelease control or offer to release control, either to distributionsystem 803 or to other actors.

As described above, the distribution system may control access to datafrom the tool string. This control may be implemented by routing onlythe data appropriate for consumption to a particular host or client.Alternatively, control may be implemented by using differentdictionaries, encryption, or other security measures for data intendedfor an actor having a first level of privileges than for other dataintended for another actor having a second level of privileges differentthan the first level. For example a different encryption key may be usedfor each level of privilege or each actor. This may be particularlyuseful in system embodiments employing a distributed remote cluster (seeFIG. 5D).

Techniques for obtaining EM propagation measurements (e.g., relativephase and attenuation) are well known in the art. See for example, U.S.patent application Ser. No. 13/991,029 to Dorovsky et al. and U.S.patent application Ser. No. 15/280,815 to Kouchmeshky et al., eachincorporated herein by reference.

Acoustic beam reflection may be conventionally processed to detectazimuthal thickness of multiple tubulars (e.g., production tubing, firstand second casing, etc.) as well as position, cement thickness, boreholediameter, bond quality, and so on. See, for example, U.S. Pat. No.7,525,872 to Tang et al., U.S. Pat. No. 7,787,327 to Tang et al., U.S.Pat. No. 8,788,207 to Pei et al., U.S. Pat. No. 8,061,206 to Bolshakov,U.S. Pat. No. 9,103,196 to Zhao et al., and U.S. Pat. No. 6,896,056 toMendez et al., each commonly owned with the present application andincorporated herein by reference in its entirety.

Methods include generating an electromagnetic (EM) field using an EMtransmitter of the logging tool to produce interactions between theelectromagnetic field and a volume of interest. Evaluation of theresulting measurements may be carried out in accordance with techniquesknown to those of skill in the art. See, for example, U.S. Pat. No.7,403,000 to Barolak et al. and U.S. Pat. No. 7,795,864 to Barolak etal., each incorporated herein by reference in its entirety.

The tool may include a body (e.g., BHA, housing, enclosure, drillstring, wireline tool body) having pads extended on extension devices.Two to six pads may be used. The extension devices may be electricallyoperated, electromechanically operated, mechanically operated orhydraulically operated. With the extension devices fully extended, thepads may engage the wellbore 580 and make measurements indicative of atleast one parameter of interest of the earth formation or wellboreinfrastructure (e.g., casing). Such devices are well-known in the art.See, for example, U.S. Pat. No. 7,228,903 to Wang et al., herebyincorporated by reference in its entirety.

U.S. Pat. No. 8,055,448 B2 to Mathiszik et al., having the same assigneeas the present disclosure and the contents of which are incorporatedherein by reference, discloses further improvements in MWD acousticimaging. A downhole acoustic logging tool is used for generating aguided borehole wave that propagates into the formation as a body wave,reflects from an interface and is converted back into a guided boreholewave. Guided borehole waves resulting from reflection of the body waveare used to image a reflector. U.S. Pat. No. 8,811,114 B2 to Geerits etal., having the same assignee as the present disclosure and the contentsof which are incorporated herein by reference, discloses furtherimprovements in MWD acoustic imaging.

The volume of interest may be a plurality of nested conductive tubularsin the borehole, and estimating the property may be carried out byestimating a property corresponding to at least one tubular (andpossibly all) of the plurality of nested conductive tubulars. Theproperty corresponding to each conductive tubular may include at leastone of: i) location of the tubular; ii) thickness of the tubular; andiii) at least one property of a defect of the tubular; iv) a presence ofa completion component outside at least one tubular; and v) a propertyof a completion component outside at least one tubular.

The term “substantially real-time” as applied to methods of the presentdisclosure refers to an action performed (e.g., estimation, modeling,processing, and so on) while the sensor is still downhole, after thegeneration of the information and prior to movement of the sensor anappreciable distance within the context of evaluating the borehole orformation at an associated resolution, such as, for example, a distanceof 50 meters, 25 meters, 10 meters, 5 meters, 1 meter, 0.5 meters, 10centimeters, 1 centimeter, or less; and may be defined as estimation ofthe parameter of interest or production of the current iteration of amodel within 15 minutes of generating the information, within 10 minutesof generation, within 5 minutes of generation, within 3 minutes ofgeneration, within 2 minutes of generation, within 1 minute ofgeneration, or less. Substantially simultaneously as applied to methodsof the present disclosure refers to actions performed (e.g., estimation,modeling, processing, and so on) with overlap of the first and secondaction (simultaneously), or an amount of time not greater than a timeafter an end of the first action and prior to movement of the instrumentan appreciable distance within the context of evaluating the borehole orformation at an associated resolution, such as, for example, a distanceof 50 meters, 25 meters, 10 meters, 5 meters, 1 meter, 0.5 meters, 10centimeters, 1 centimeter, or less; and may be defined as estimation ofthe parameter of interest or production of the current iteration of amodel within 15 minutes of the end of the first action, within 10minutes of the end of the first action, within 5 minutes of the end ofthe first action, within 3 minutes of the end of the first action,within 2 minutes of the end of the first action, within 1 minute of theend of the first action, or less. Substantially all means enough data tomaintain the benefit of maximum resolution, such as at least 90 percentof the data over an interval, at least 95 percent of the data over aninterval, at least 98 percent of the data over an interval, at least 99percent of the data over an interval, up to an including 100 percent ofthe data.

Methods may include conducting further operations in dependence upon theproperty. The further operations may include at least one of: i)geosteering; ii) drilling additional wellbores in the formation; iii)performing additional measurements on the formation; iv) estimatingadditional parameters of the formation; v) installing equipment in thewellbore; vi) repairing infrastructure; vii) optimizing present orfuture development in the formation or in a similar formation; viii)optimizing present or future exploration in the formation or in asimilar formation; and ix) producing one or more hydrocarbons from theformation.

Aspects of the present disclosure include systems and methods forformation evaluation, such as performing well logging in a boreholeintersecting an earth formation, as well as casing integrity inspection.“Well logging,” as used herein refers to the acquisition of informationfrom a downhole tool located in a borehole, whether the borehole iscased or open, during or after the formation of the borehole. Theinformation may include parameters of interest of the formation, theborehole, infrastructure installed in the formation (e.g., casing,production tubing, etc.), downhole fluids in one of these, orcombinations of the same. Drilling systems in accordance with aspects ofthe present disclosure may have a plurality of “logging-while-drilling”(‘LWD’) or “measurement-while-drilling” (‘MWD’) instruments as part of abottomhole assembly. Operational processes may include computerprocesses (e.g., applications or routines), physical processes (pullinga lever), telemetry, monitoring (e.g., outputting sensor data), control,actuation, chemical processes, and the like.

Embodiments may include, during a logging operation, using a Wide AreaNetwork (WAN) to transmit raw logging data from the logging site to areceiving node at at least one of: i) the first instrument controlstation; ii) the second instrument control station; iii) the welloperation control host; iv) a data processing system remote from thelogging site; v) a display station remote from the logging site; and vi)a data archiving system remote from the logging site. The data may betransmitted in substantially real-time.

While the foregoing disclosure is directed to the one mode embodimentsof the disclosure, various modifications will be apparent to thoseskilled in the art. It is intended that all variations be embraced bythe foregoing disclosure.

What is claimed is:
 1. A method of remote well operation control, themethod comprising: conducting, with a plurality of remote well operationcontrol hosts operating on corresponding remote well logging dataacquisition management systems, a well operation using a well operationsystem at a well, wherein the well operation system includes a carrierhaving disposed thereon at least one logging instrument, comprising:establishing a first operational control relationship between thecarrier and a first of the plurality of remote well operation controlhosts sufficient for the first remote well operation control host tocontrol the carrier responsive to at least one well-logging command fromthe first remote well operation control host; establishing a secondoperational control relationship between a selected one of the at leastone logging instrument and a second remote well operation control hostof the plurality different than the first, the operational controlrelationship sufficient for the second remote well operation controlhost to control the at least one logging instrument responsive to atleast one well-logging command from the second remote well operationcontrol host and receive logging data.
 2. The method of claim 1,comprising: operating the carrier responsive to at least onewell-logging command received from the first remote well operationcontrol host of the plurality; and operating the logging instrumentresponsive to at least one well-logging command received from the secondremote well operation control host of the plurality.
 3. The method ofclaim 2, further comprising, over at least one interval of time,identically processing the logging data at the local well operationcontrol host in parallel with processing the logging data at the secondremote well operation control host, substantially simultaneously.
 4. Themethod of claim 1 further comprising, during a logging operation, usinga Wide Area Network (WAN) to transmit substantially all substantiallymaximum resolution raw well logging data generated by the selected oneof the at least one logging instrument from the well to at least one ofthe plurality of remote well operation control hosts; and using thelogging data to control the well operation with at least one secondcommand in substantially real-time from the at least one of theplurality of remote well operation control hosts responsive to thelogging data received.
 5. The method of claim 1 further comprisingoperating a second logging instrument responsive to at least onewell-logging command from the second remote well operation control host.6. The method of claim 1 further comprising operating a second logginginstrument on the carrier responsive to at least one well-loggingcommand from a third remote well operation control host of the pluralitydifferent than the first and second.
 7. The method of claim 1 comprisingwherein the carrier comprises at least one of i) a drill string; ii) awireline; and iii) a downhole tool.
 8. The method of claim 1 wherein thewell operation comprises at least one of: i) geosteering; ii) drillingat least one borehole in a formation; iii) performing measurements on aformation; iv) estimating parameters of a formation; v) installingequipment in a borehole; vi) evaluating a formation; vii) optimizingpresent or future development in a formation or in a similar formation;viii) optimizing present or future exploration in a formation or in asimilar formation; ix) producing one or more hydrocarbons from aformation; x) performing maritime logging operations of a seabed.
 9. Themethod of claim 1, further comprising: conducting, with the plurality ofremote well operation control hosts operating on the correspondingremote well logging data acquisition management systems, a second welloperation using a second well operation system at a second well remotefrom the first well, wherein the second well operation system includes asecond conveyance device having disposed thereon a third logginginstrument and a fourth logging instrument, comprising: establishing athird operational control relationship between the third logginginstrument and a first of the plurality of remote well operation controlhosts sufficient for the first remote well operation control host tocontrol the third logging instrument responsive to at least onewell-logging command from the first remote well operation control host;establishing a fourth operational control relationship between a fourthlogging instrument and the second remote well operation control host,the operational control relationship sufficient for the second remotewell operation control host to control the fourth logging instrumentresponsive to at least one well-logging command from the second remotewell operation control host.
 10. The method of claim 9 furthercomprising enabling i) operation of the carrier by the first remote welloperation control host, ii) operation of the selected one of the atleast one logging instrument by the second remote well operation controlhost, iii) operation of the third logging instrument by the first remotewell operation control host, and iv) operation of the fourth logginginstrument by the second remote well operation control host, by: using amaster remote well operation control host, of the plurality of remotewell operation control hosts, on a corresponding remote well loggingdata acquisition management system to establish the third operationalcontrol relationship and the fourth operational control relationship.11. The method of claim 1 further comprising enabling operation of thecarrier by the first remote well operation control host and operation ofthe selected one of the at least one logging instrument by the secondremote well operation control host by using a master remote welloperation control host, of the plurality of remote well operationcontrol hosts, on a corresponding remote well logging data acquisitionmanagement system to distribute control capabilities by establishing thefirst operational control relationship and the second operationalcontrol relationship.
 12. The method of claim 1 further comprisingestablishing at least one of: i) the first operational controlrelationship, and ii) the second operational control relationship independence upon a role associated with at least one of: i) the firstremote well operation control host, and ii) the second remote welloperation control host.
 13. A method of remote well operation control,the method comprising: conducting, with a plurality of remote welloperation control hosts operating on corresponding remote well loggingdata acquisition management systems, a well operation using a welloperation system at a well, wherein the well operation system includes acarrier having disposed thereon a plurality of logging instruments,comprising: establishing a first operational control relationshipbetween a first logging instrument of the plurality of logginginstruments and a first of the plurality of remote well operationcontrol hosts, the operational control relationship sufficient for thefirst remote well operation control host to control the first logginginstrument responsive to at least one well-logging command from thefirst remote well operation control host; establishing a secondoperational control relationship between a second of the plurality oflogging instruments and a second remote well operation control host ofthe plurality different than the first, the operational controlrelationship sufficient for the second remote well operation controlhost to control the second logging instrument responsive to at least onewell-logging command from the second remote well operation control host.14. A method of conducting well operations, the method comprising:allocating control of an operational resource located at a well, thecontrol of the resource sufficient for conducting at least a portion ofthe well operations, comprising: maintaining a database associating aplurality of remote well operational control hosts with correspondingroles, wherein at least some roles of the corresponding roles areassociated with privileges to corresponding operational resources; andallocating control of an operational resource to a first remote welloperational control host of the plurality in dependence upon the roleassociated with the remote well operational control host.
 15. The methodof claim 14, further comprising determining an operational state of theresource; and wherein allocating control of the operational resource tothe remote well operational control host comprises allocating control ofthe operational resource to the remote well operational control host independence upon the role associated with the remote well operationalcontrol host and the operational state of the resource.
 16. The methodof claim 14, further comprising determining an operational state of thewell; wherein allocating control of the operational resource to theremote well operational control host comprises allocating control of theoperational resource to the remote well operational control host independence upon the role associated with the remote well operationalcontrol host and the operational state of the well.
 17. The method ofclaim 14, further comprising allocating control of the operationalresource to a local well operation control host while in a defaultoperational state.
 18. The method of claim 14, wherein the allocatingcomprises an initial allocation of the role.
 19. The method of claim 14,wherein the allocating includes a role modification comprising:identifying the first remote well operational control host as beingassociated with the role modification; associating the first remote welloperational control host with the role.
 20. The method of claim 14,further comprising a role modification, comprising: identifying a secondremote well operational control host as being associated with the rolemodification; associating the second remote well operational controlhost with the role.
 21. The method of claim 20, wherein the role isassociated with a credentials profile, and the second remote welloperational control host has associated therewith credentials, andidentifying a second remote well operational control host comprises:generating a comparison of the credentials against the credentialsprofile; and selecting the second remote well operational control hostin dependence upon the comparison and at least one selection rule. 22.The method of claim 14, wherein the allocating includes a rolemodification comprising: modifying at least a pre-existing roleassociated with the first remote well operational control host to therole; and modifying at least the role, associated with a second remotewell operational control host, to another role.
 23. The method of claim22 further comprising triggering the role modification in response todetecting a role shift event.
 24. The method of claim 14, wherein atleast some roles of the corresponding roles are associated withconstraints.